UGI (UGI) 10-K 22 Nov 16 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2016	Nov. 15, 2016	Mar. 31, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	UGI CORP /PA/
Entity Central Index Key	884,614
Document Type	10-K
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 6,917,708,915
Entity Common Stock, Shares Outstanding		172,983,624

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Current assets
Cash and cash equivalents	$ 502.8	$ 369.7
Restricted cash	15.6	69.3
Accounts receivable (less allowances for doubtful accounts of $27.3 and $29.7, respectively)	551.6	619.7
Accrued utility revenues	12.8	12.1
Inventories	210.3	239.9
Deferred income taxes	0	7.8
Utility regulatory assets	3.2	4.1
Derivative instruments	30.9	23.3
Prepaid expenses and other current assets	96.6	113.9
Total current assets	1,423.8	1,459.8
Property, plant and equipment
Non-utility	5,346.4	5,075.6
Utilities	2,998.9	2,753.5
Total property, plant and equipment	8,345.3	7,829.1
Accumulated depreciation and amortization	(3,107.3)	(2,835)
Net property, plant, and equipment	5,238	4,994.1
Goodwill	2,989	2,953.4	[1]
Intangible assets, net	580.3	610.1
Utility regulatory assets	391.9	300.1
Derivative instruments	6.5	16.3
Other assets	217.7	180.4
Total assets	10,847.2	10,514.2	[1]
Current liabilities
Current maturities of long-term debt	29.5	257.9
Short-term borrowings	291.7	189.9	[1]
Accounts payable	391.2	392.9
Employee compensation and benefits accrued	115.1	133.4
Deposits and advances	241.3	242
Derivative instruments	48.5	121.8
Accrued interest	48.1	57.4
Other current liabilities	276.6	283.5
Total current liabilities	1,442	1,678.8
Debt and other liabilities
Long-term debt	3,766	3,409.5
Deferred income taxes	1,216.2	1,134
Deferred investment tax credits	3.3	3.6
Derivative instruments	21.9	31.2
Other noncurrent liabilities	796	684.7
Total liabilities	7,245.4	6,941.8
Commitments and contingencies (Note 15)
UGI Corporation stockholders’ equity:
UGI Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,894,141 and 173,806,991 shares, respectively)	1,201.6	1,214.6
Retained earnings	1,840.9	1,636.9
Accumulated other comprehensive loss	(154.7)	(114.6)
Treasury stock, at cost	(36.9)	(44.9)
Total UGI Corporation stockholders’ equity	2,850.9	2,692
Noncontrolling interests, principally in AmeriGas Partners	750.9	880.4
Total equity	3,601.8	3,572.4
Total liabilities and equity	$ 10,847.2	$ 10,514.2
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 27.3	$ 29.7
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	173,894,141	173,806,991

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
Revenues
Non-utility	$ 4,917.2	$ 5,650.4		$ 7,191.9
Utility	768.5	1,040.7		1,085.4
Revenues	5,685.7	6,691.1	[1]	8,277.3	[1]
Cost of sales (excluding depreciation shown below):
Non-utility	2,147.7	3,225.7		4,612.8
Utility	289.8	510.8		562.9
Operating and administrative expenses	1,865.9	1,773.9		1,752.6
Utility taxes other than income taxes	15.8	16.1		16.6
Depreciation	338.6	313.2		305.7
Amortization	62.3	60.9		57.2
Other operating income, net	(22.4)	(44.4)		(36.1)
Total costs and expenses	4,697.7	5,856.2		7,271.7
Operating income	988	834.9	[1]	1,005.6	[1]
Loss from equity investees	(0.2)	(1.2)	[1]	(0.1)	[1]
Loss on extinguishments of debt	(48.9)	0		0
Interest expense	(228.9)	(241.9)	[1]	(237.7)	[1]
Income before income taxes	710	591.8	[1]	767.8	[1]
Income taxes	(221.2)	(177.8)		(235.2)
Net income including noncontrolling interests	488.8	414		532.6
Deduct net income attributable to noncontrolling interests, principally in AmeriGas Partners	(124.1)	(133)	[1]	(195.4)	[1]
Net income attributable to UGI Corporation	$ 364.7	$ 281	[1]	$ 337.2	[1]
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ 2.11	$ 1.62		$ 1.95
Diluted (in dollars per share)	$ 2.08	$ 1.60		$ 1.92
Weighted-average common shares outstanding (thousands):
Basic (in shares)	173,154	173,115		172,733
Diluted (in shares)	175,572	175,667		175,231
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income including noncontrolling interests	$ 488.8	$ 414	$ 532.6
Net (losses) gains on derivative instruments (net of tax of $12.3, $(8.0) and $(12.2), respectively)	(16.5)	16.8	54
Reclassifications of net (gains) losses on derivative instruments (net of tax of $5.0, $(2.8) and $2.0, respectively)	(8.1)	1.6	(45.2)
Foreign currency translation adjustments (net of tax of $0.0, $(1.0) and $13.8, respectively)	(4.9)	(63.5)	(23.2)
Foreign currency losses on long-term intra-company transactions (net of tax of $0.0, $(6.7) and $10.6, respectively)	(1.9)	(50.6)	(19.8)
Benefit plans, principally actuarial losses (net of tax of $7.1, $1.4 and $2.6, respectively)	(10.9)	(1.2)	(5.2)
Reclassifications of benefit plans actuarial losses and net prior service credits (net of tax of $(0.4), $(0.8) and $(0.6), respectively)	2.2	1.4	1
Other comprehensive loss	(40.1)	(95.5)	(38.4)
Comprehensive income including noncontrolling interests	448.7	318.5	494.2
Deduct comprehensive income attributable to noncontrolling interests, principally in AmeriGas Partners	(124.1)	(130.9)	(186.6)
Comprehensive income attributable to UGI Corporation	$ 324.6	$ 187.6	$ 307.6

Consolidated Statements of Com6

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Tax on (loss) gain on derivative instruments	$ 12.3	$ (8)	$ (12.2)
Tax on reclassifications on derivative instruments	5	(2.8)	2
Tax on foreign currency translation	0	(1)	13.8
Tax on foreign currency gain and losses on long-term intra-company transactions	0	(6.7)	10.6
Tax on benefit plans	7.1	1.4	2.6
Tax on reclassification of benefit plans and prior service costs	$ (0.4)	$ (0.8)	$ (0.6)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income including noncontrolling interests	$ 488.8	$ 414		$ 532.6
Adjustments to reconcile net income including noncontrolling interests to net cash provided by operating activities:
Depreciation and amortization	400.9	374.1	[1]	362.9	[1]
Deferred income taxes, net	77.4	13.7		66.7
Provision for uncollectible accounts	21.7	31.6		43.5
Unrealized (gains) losses on derivative instruments	(91.6)	119.1		18.6
Equity-based compensation expense	23.8	29.2		25.8
Loss on extinguishments of debt	48.9	0		0
Settlement of UGI Utilities interest rate protection agreements	(36)	0		0
Other, net	(7.3)	(9.7)		(38.2)
Net change in:
Accounts receivable and accrued utility revenues	37.3	163.3		18.1
Inventories	29.4	181.4		(65.1)
Utility deferred fuel costs, net of changes in unsettled derivatives	(22.7)	51.8		(17.6)
Accounts payable	(40)	(134.9)		3.7
Other current assets	(8.6)	(25.6)		(1.2)
Other current liabilities	47.7	(44.2)		55.6
Net cash provided by operating activities	969.7	1,163.8		1,005.4
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment	(563.8)	(490.6)		(456.8)
Acquisitions of businesses, net of cash acquired	(61.2)	(447.5)		(37.1)
Decrease (increase) in restricted cash	53.7	(52.8)		(8.3)
Other, net	12.7	14.6		14.6
Net cash used by investing activities	(558.6)	(976.3)		(487.6)
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends on UGI Common Stock	(160.7)	(153.5)		(136.1)
Distributions on AmeriGas Partners publicly held Common Units	(257.3)	(248.9)		(237.7)
Issuances of debt, net of issuance costs	1,629.5	660.3		174.5
Repayments of debt, including redemption premiums	(1,569.9)	(429.4)		(242.6)
Receivables Facility net borrowings (repayments)	6	12		(22.5)
Increase (decrease) in short-term borrowings	95.7	(31.9)		5.8
Issuances of UGI Common Stock	13.7	11.9		10.9
Repurchases of UGI Common Stock	(47.6)	(34.1)		(39.8)
Other	15.5	(3.5)		11.8
Net cash used by financing activities	(275.1)	(217.1)		(475.7)
Effect of exchange rate changes on cash and cash equivalents	(2.9)	(20.2)		(11.9)
Cash and cash equivalents increase (decrease)	133.1	(49.8)		30.2
CASH AND CASH EQUIVALENTS
End of year	502.8	369.7		419.5
Beginning of year	369.7	419.5		389.3
Increase (decrease)	133.1	(49.8)		30.2
Cash paid for:
Interest	228.9	227		228.3
Income taxes	$ 134.5	$ 173.1		$ 141.6
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Consolidated Statements of Chan

Consolidated Statements of Changes In Equity - USD ($) $ in Millions	Total	Total UGI Corporation Stockholder's Equity	Common Stock, Without Par Value	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Treasury Stock	Noncontrolling Interests
Balance, beginning of year at Sep. 30, 2013			$ 1,208.1	$ 1,308.3	$ 8.4	$ (32.3)	$ 1,055.4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Employee and director plans (including losses on treasury stock transactions), net of tax withheld			(16.4)
Employee and director plans						65.8
Excess tax benefits realized on equity-based compensation			12.5
Equity-based compensation expense			11.4
Loss from acquisition of noncontrolling interests through business combination			0
Net income attributable to UGI Corporation	$ 532.6			337.2			195.4
Cash dividends on common stock ($0.930, $0.890 and $0.791 per share, respectively)				(136.1)
Net (losses) gains on derivative instruments	54				21.6		32.4
Reclassification of net (gains) losses on derivative instruments	(45.2)				(4)
Benefit plans, principally actuarial losses					(5.2)
Reclassification of benefit plans actuarial losses and net prior service credits	(1)				1
Foreign currency losses on long-term intra-company transactions	(19.8)				(19.8)
Foreign currency translation adjustments	(23.2)				(23.2)
Repurchases of common stock						(39.8)
Reacquired common stock - employee and director plans						(38.4)
Reclassification of net gains on derivative instruments							(41.2)
Dividends and distributions							(238)
Change in noncontrolling interests as a result of business combination							0
Other							0.1
Balance, end of year at Sep. 30, 2014	3,663.2	$ 2,659.1	1,215.6	1,509.4	(21.2)	(44.7)	1,004.1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Employee and director plans (including losses on treasury stock transactions), net of tax withheld			(22.1)
Employee and director plans						40.5
Excess tax benefits realized on equity-based compensation			8.3
Equity-based compensation expense			13.2
Loss from acquisition of noncontrolling interests through business combination			(0.4)
Net income attributable to UGI Corporation	414			281			133
Cash dividends on common stock ($0.930, $0.890 and $0.791 per share, respectively)				(153.5)
Net (losses) gains on derivative instruments	16.8				16.8		0
Reclassification of net (gains) losses on derivative instruments	1.6				3.7
Benefit plans, principally actuarial losses					(1.2)
Reclassification of benefit plans actuarial losses and net prior service credits	(1.4)				1.4
Foreign currency losses on long-term intra-company transactions	(50.6)				(50.6)
Foreign currency translation adjustments	(63.5)				(63.5)
Repurchases of common stock						(34.1)
Reacquired common stock - employee and director plans						(6.6)
Reclassification of net gains on derivative instruments							(2.1)
Dividends and distributions							(249.4)
Change in noncontrolling interests as a result of business combination							(5.2)
Other							0
Balance, end of year at Sep. 30, 2015	3,572.4	2,692	1,214.6	1,636.9	(114.6)	(44.9)	880.4
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Employee and director plans (including losses on treasury stock transactions), net of tax withheld			(39.7)
Employee and director plans						84.7
Excess tax benefits realized on equity-based compensation			15.5
Equity-based compensation expense			11.2
Loss from acquisition of noncontrolling interests through business combination			0
Net income attributable to UGI Corporation	488.8			364.7			124.1
Cash dividends on common stock ($0.930, $0.890 and $0.791 per share, respectively)				(160.7)
Net (losses) gains on derivative instruments	(16.5)				(16.5)		0
Reclassification of net (gains) losses on derivative instruments	(8.1)				(8.1)
Benefit plans, principally actuarial losses					(10.9)
Reclassification of benefit plans actuarial losses and net prior service credits	(2.2)				2.2
Foreign currency losses on long-term intra-company transactions	(1.9)				(1.9)
Foreign currency translation adjustments	(4.9)				(4.9)
Repurchases of common stock						(47.6)
Reacquired common stock - employee and director plans						(29.1)
Reclassification of net gains on derivative instruments							0
Dividends and distributions							(257.3)
Change in noncontrolling interests as a result of business combination							0
Other							3.7
Balance, end of year at Sep. 30, 2016	$ 3,601.8	$ 2,850.9	$ 1,201.6	$ 1,840.9	$ (154.7)	$ (36.9)	$ 750.9

Consolidated Statements of Cha9

Consolidated Statements of Changes in Equity (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Retained Earnings
Cash dividends on Common Stock per share (in dollars per share)	$ 0.930	$ 0.890	$ 0.791

Nature of Operations

Nature of Operations	12 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations	Note 1 — Nature of Operations UGI Corporation (“UGI”) is a holding company that, through subsidiaries and affiliates, distributes, stores, transports and markets energy products and related services. In the United States, we (1) are the general partner and own limited partner interests in a retail propane marketing and distribution business; (2) own and operate natural gas and electric distribution utilities; (3) own all or a portion of electricity generation facilities; and (4) own and operate an energy marketing, midstream infrastructure, storage, natural gas gathering, natural gas production and energy services business. Internationally, we market and distribute propane and other liquefied petroleum gases (“LPG”) in Europe. We refer to UGI and its consolidated subsidiaries collectively as “the Company,” “we” or “us.” We conduct a domestic propane marketing and distribution business through AmeriGas Partners, L.P. (“AmeriGas Partners”). AmeriGas Partners is a publicly traded limited partnership that conducts a national propane distribution business through its principal operating subsidiary AmeriGas Propane, L.P. (“AmeriGas OLP”). AmeriGas Partners and AmeriGas OLP are Delaware limited partnerships. UGI’s wholly owned second-tier subsidiary, AmeriGas Propane, Inc. (the “General Partner”), serves as the general partner of AmeriGas Partners and AmeriGas OLP. We refer to AmeriGas Partners and its subsidiaries together as the “Partnership” and the General Partner and its subsidiaries, including the Partnership, as “AmeriGas Propane.” At September 30, 2016 , the General Partner held a 1% general partner interest and a 25.3% limited partner interest in AmeriGas Partners and held an effective 27.1% ownership interest in AmeriGas OLP. Our limited partnership interest in AmeriGas Partners comprises AmeriGas Partners Common Units (“Common Units”). The remaining 73.7% interest in AmeriGas Partners comprises Common Units held by the public. The General Partner also holds incentive distribution rights that entitle it to receive distributions from AmeriGas Partners in excess of its 1% general partner interest under certain circumstances (see Note 14 ). Our wholly owned subsidiary, UGI Enterprises, Inc. (“Enterprises”), through subsidiaries, conducts (1) an LPG distribution business in France, Belgium, the Netherlands and Luxembourg (“UGI France”); (2) an LPG distribution business in central, northern and eastern Europe (“Flaga”); and (3) an LPG distribution business in the United Kingdom (“AvantiGas”). On May 29, 2015, UGI France SAS (a Société par actions simplifiée) (“France SAS”) (formerly UGI Bordeaux Holding), an indirect wholly owned subsidiary of UGI, purchased all of the outstanding shares of Totalgaz SAS (the “Totalgaz Acquisition”), a retail distributor of LPG in France. The retail LPG distribution business of Totalgaz SAS and its subsidiaries is referred to herein as “Finagaz” and is included in our UGI France reportable segment (see Notes 4 and 21 ). The retail LPG distribution business of UGI France prior to the Totalgaz Acquisition is also referred to herein as “Antargaz.” In March 2016, we sold our LPG distribution business located in the Nantong region of China. The sale did not have a material impact on the consolidated financial statements. We refer to our foreign LPG operations collectively as “UGI International.” UGI Energy Services, LLC (“Energy Services, LLC”), a wholly owned subsidiary of Enterprises, conducts directly and through subsidiaries an energy marketing, midstream transmission, liquefied natural gas (“LNG”), storage, natural gas gathering, natural gas production and energy services business primarily in the Mid-Atlantic and Northeast U.S. In addition, Energy Services, LLC’s wholly owned subsidiary, UGI Development Company (“UGID”), owns all or a portion of electricity generation facilities principally located in Pennsylvania. A first-tier subsidiary of Enterprises also conducts heating, ventilation, air-conditioning, refrigeration and electrical contracting businesses in the Mid-Atlantic region (“HVAC”). Energy Services, LLC and its subsidiaries’ storage, LNG, and portions of its midstream transmission operations are subject to regulation by the Federal Energy Regulatory Commission ("FERC"). We refer to the businesses of Energy Services, LLC and its subsidiaries (excluding UGID) and HVAC as “Energy Services.” We refer to Energy Services and UGID collectively as “Midstream & Marketing.” UGI Utilities, Inc. (“UGI Utilities”) conducts a natural gas distribution utility business (“Gas Utility”) directly and through its wholly owned subsidiaries UGI Penn Natural Gas, Inc. (“PNG”) and UGI Central Penn Gas, Inc. (“CPG”). UGI Utilities, PNG and CPG own and operate natural gas distribution utilities in eastern, northeastern and central Pennsylvania and in a portion of one Maryland county. UGI Utilities also owns and operates an electric distribution utility in northeastern Pennsylvania (“Electric Utility”). UGI Utilities’ natural gas distribution utility is referred to as “UGI Gas.” Gas Utility is subject to regulation by the Pennsylvania Public Utility Commission (“PUC”) and, with respect to a small service territory in one Maryland county, the Maryland Public Service Commission. Electric Utility is subject to regulation by the PUC. UGI Utilities is used herein as an abbreviated reference to UGI Utilities, Inc. or, collectively, UGI Utilities, Inc. and its subsidiaries.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2 — Summary of Significant Accounting Policies Basis of Presentation Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Certain prior-year amounts have been reclassified to conform to the current-year presentation. Principles of Consolidation The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s interests in the Partnership, and outside ownership interests in other consolidated but less than 100% -owned subsidiaries, as noncontrolling interests. We eliminate intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2016 and 2015 . Investments in business entities that are not publicly traded and in which we do not have significant influence over operating and financial policies are accounted for using the cost method. Such investments are recorded in other assets on the Consolidated Balance Sheets and totaled $70.1 and $70.8 at September 30, 2016 and 2015 , respectively (including $18.0 and $17.9 , respectively, associated with our approximate 3.5% interest in a private equity partnership that invests in renewable energy companies). Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis. Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 8 . Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts. GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: • Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. • Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. • Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments. Derivative Instruments Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. Effective October 1, 2014, UGI International determined on a prospective basis that it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues, as appropriate, on the Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in cash flow from financing activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 17 . Foreign Currency Translation Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income. Revenue Recognition Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services. UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in utility taxes other than income taxes on the Consolidated Statements of Income in accordance with regulatory practice. Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible. LPG Delivery Expenses Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in depreciation on the Consolidated Statements of Income. Income Taxes AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. AmeriGas OLP has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation. UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income taxes for assets placed in service after Fiscal 2011 and are amortized over the estimated useful life of the property for assets placed in service prior to Fiscal 2012. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , interest income or expense recognized in income taxes on the Consolidated Statements of Income was not material. Earnings Per Common Share Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards. In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 : (Thousands of shares) 2016 2015 2014 Weighted-average common shares outstanding for basic computation 173,154 173,115 172,733 Incremental shares issuable for stock options and common stock awards (a) 2,418 2,552 2,498 Weighted-average common shares outstanding for diluted computation 175,572 175,667 175,231 (a) For Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , there were 38 shares, 1 share and 0 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive. Cash and Cash Equivalents All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents. Restricted Cash Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal. At September 30, 2015, restricted cash also includes $14.3 associated with a construction escrow agreement. Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for LPG, specific identification for appliances and the first-in, first-out (“FIFO”) method for all other inventories. Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 10 to 40 years for buildings and improvements; 6 to 40 years for storage and customer tanks and cylinders; 25 to 40 years for electricity generation facilities; 25 to 40 years for pipeline and related assets, and 3 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and UGI France-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding 10 years. We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. The composite annual rate for depreciable property at our Gas Utility was 2.2% in Fiscal 2016 , 2.2% in Fiscal 2015 and 2.3% in Fiscal 2014 . The composite annual rate for depreciable property at our Electric Utility was 2.5% in Fiscal 2016 , 2.5% in Fiscal 2015 and 2.5% in Fiscal 2014 . When UGI Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets. We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit generally not exceeding 10 years once the installed software is ready for its intended use. No depreciation expense is included in cost of sales in the Consolidated Statements of Income. Goodwill and Intangible Assets In accordance with GAAP relating to intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 11 ). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames and noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. Each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2016, the Company changed the measurement date for performing its annual goodwill impairment tests from September 30 to July 31. This voluntary change in accounting principle, applied prospectively, is preferable as it aligns the annual goodwill impairment test date more closely with the Company’s internal budgeting process and did not delay, accelerate or avoid an impairment of the Company’s goodwill. For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, the implied fair value of goodwill is determined in the same manner as goodwill is recognized in a business combination. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to such excess. There were no accumulated impairment losses at September 30, 2016 and 2015 , and no provisions for goodwill or other intangible asset impairments were recorded during Fiscal 2016 , Fiscal 2015 or Fiscal 2014 . Impairment of Long-Lived Assets and Cost Basis Investments We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets. No material provisions for impairments were recorded during Fiscal 2016 , Fiscal 2015 or Fiscal 2014 . We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary. No other-than-temporary impairment losses were recognized in Fiscal 2016 , Fiscal 2015 or Fiscal 2014 . Deferred Debt Issuance Costs During the fourth quarter of Fiscal 2016, we adopted new accounting guidance regarding the classification of deferred debt issuance costs (see Note 3 ). Deferred debt issuance costs associated with long-term debt are now reflected as a direct deduction from the carrying amount of such debt rather than as a deferred charge. Deferred debt issuance costs associated with line of credit facilities remain classified as other assets on our Consolidated Balance Sheets. We are amortizing deferred debt issuance costs over the terms of the related debt. Total deferred debt issuance costs at September 30, 2016 and 2015 were $40.8 and $36.3 , respectively. As of September 30, 2016 and 2015 , the Company has reflected $36.8 and $32.4 , respectively, of such costs as a reduction to long-term debt, including current maturities, on the Consolidated Balance Sheets. Refundable Tank and Cylinder Deposits Included in other noncurrent liabilities on our Consolidated Balance Sheets are customer paid deposits primarily on UGI France owned tanks and cylinders of $267.2 and $273.4 at September 30, 2016 and 2015 , respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms. Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites. Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 15 . Employee Retirement Plans We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our U.S. pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7 ). Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity on our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period. We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards). We expect to adopt new accounting guidance that simplifies and clarifies certain aspects of the accounting for and presentation of share-based payments during the first quarter of Fiscal 2017 (see Note 3). For additional information on our equity-based compensation plans and related disclosures, see Note 13 .

Accounting Changes

Accounting Changes	12 Months Ended
	Sep. 30, 2016
Accounting Changes and Error Corrections [Abstract]
Accounting Changes	Note 3 — Accounting Changes Adoption of New Accounting Standards Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, accordingly, balance sheets prior to Fiscal 2016 have not been reclassified. Debt Issuance Costs. During the fourth quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of debt issuance costs. This new guidance amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. As required by the new guidance, prior period amounts have been reclassified. See Note 2 under “Deferred Debt Issuance Costs” for a description of the impact on the Consolidated Balance Sheets. Accounting Standards Not Yet Adopted Cash Flow Classification. In August 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Employee Share-Based Payments . In March 2016, the FASB issued ASU No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the accounting for employee share-based payment transactions including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with share-based awards will be recognized as income tax benefit or expense in the income statement and the tax effects of exercised or vested awards will be treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding will not include windfall tax benefits which could result in more incremental shares outstanding in the diluted shares calculation. The Company expects to adopt the new accounting guidance during the first quarter of Fiscal 2017. The amendments most likely to impact the Company, principally those requiring recognition of excess tax benefits and tax deficiencies in the income statement and the impact on the treasury stock method in computing diluted shares outstanding, will be applied prospectively. Based upon the number of share-based awards currently outstanding, we do not believe that the adoption of the new guidance will have a material impact on diluted shares outstanding. The impact of the adoption of the new guidance on our net income will depend upon the timing of the exercise or vesting of share-based awards as well as the amount of any associated excess tax benefits or deficiencies. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Acquisitions	Note 4 — Acquisitions Acquisition of Totalgaz On May 29, 2015 (the “Acquisition Date”), UGI, through its wholly owned indirect subsidiary, France SAS, acquired all of the outstanding shares of Totalgaz SAS, a retail distributor of LPG in France, for €451.8 ( $496.6 ) in cash, including €30.0 ( $33.0 ) for estimated Acquisition Date working capital. In November 2015, France SAS received €1.1 ( $1.2 ) of cash as a result of the completion of the final working capital amount. The Totalgaz Acquisition was consummated pursuant to the terms of a Share Purchase Agreement dated November 11, 2014, between Total Marketing Services, a subsidiary of global energy company, Total, and France SAS. The Totalgaz Acquisition nearly doubles our retail LPG distribution business in France and is consistent with our growth strategies, one of which is to grow our core business through acquisitions. The Totalgaz Acquisition was funded from existing cash balances and a portion of loan proceeds from France SAS’s May 29, 2015, issuance of a €600 term loan under its 2015 Senior Facilities Agreement (see Note 5). The Company accounted for the Totalgaz Acquisition using the acquisition method. The components of the final Totalgaz purchase price allocation are as follows: Assets acquired: Cash $ 86.8 Accounts receivable (a) 170.3 Prepaid expenses and other current assets 11.0 Property, plant and equipment 375.6 Intangible assets (b) 91.3 Other assets 21.4 Total assets acquired $ 756.4 Liabilities assumed: Accounts payable 109.2 Other current liabilities 103.5 Deferred income taxes 117.5 Other noncurrent liabilities 113.4 Total liabilities assumed $ 443.6 Goodwill 183.8 Net consideration transferred (including working capital adjustments) $ 496.6 (a) Approximates the gross contractual amounts of receivables acquired. (b) Comprises $79.3 of customer relationships and $12.0 of tradenames ( $8.3 of which is subject to amortization), having average amortization periods of 15 years . We allocated the purchase price of the acquisition to identifiable intangible assets and property, plant and equipment based on estimated fair values as follows: • Customer relationships were valued using a multi-period, excess earnings method. Key assumptions used in this method include discount rates, growth rates and cash flow projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; • Tradenames were valued using the relief from royalty method, which estimates our theoretical royalty savings from ownership of the tradenames. Key assumptions used in this method include discount rates, royalty rates, growth rates and sales projections. These assumptions are most sensitive and susceptible to change as they require significant management judgment; and • Property, plant and equipment were valued based on estimated fair values primarily using depreciated replacement cost and market value methods. The excess of the purchase price for the Totalgaz Acquisition over the fair values of the assets acquired and liabilities assumed has been reflected as goodwill, assigned to the UGI France reportable segment, and results principally from anticipated synergies and value creation resulting from the Company’s combined LPG businesses in France. The goodwill is not deductible for income tax purposes. The Company recognized $16.1 of direct transaction-related costs associated with the Totalgaz Acquisition during Fiscal 2015, which are reflected primarily in operating and administrative expenses on the Consolidated Statements of Income. The acquisition of Totalgaz did not have a material impact on the Company’s revenues or net income attributable to UGI for the year ended September 30, 2015. The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for Fiscal 2015 and Fiscal 2014 as if the Totalgaz Acquisition had occurred on October 1, 2013. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2013. Amounts in the table below exclude costs associated with extinguishment of debt under Antargaz’ 2011 Senior Facilities Agreement (see Note 5 ): 2015 2014 As Reported Pro Forma Adjusted As Pro Forma Revenues $ 6,691.1 $ 7,065.8 $ 8,277.3 $ 8,999.6 Net income attributable to UGI Corporation $ 281.0 $ 341.2 $ 337.2 $ 385.5 Earnings per common share attributable to UGI Corporation stockholders: Basic $ 1.62 $ 1.97 $ 1.95 $ 2.23 Diluted $ 1.60 $ 1.94 $ 1.92 $ 2.20 The unaudited pro forma consolidated information is not necessarily indicative of the results that would have occurred had the Totalgaz Acquisition occurred on the date indicated nor are they necessarily indicative of future operating results. In connection with the Totalgaz Acquisition, the Company agreed with the French Competition Authority (the “FCA”) to divest certain assets and investments of Totalgaz SAS and certain assets of Antargaz located in France no later than August 15, 2016. The time period has been extended for a few additional months for the purpose of finalizing certain proposed sales; to the extent that certain properties are not sold, an alternative remedy will apply. Following the closing of the Totalgaz Acquisition, two competitors in the French LPG distribution market challenged the decision of the FCA. The competitors’ request for interim measures suspending the effectiveness of the agreed remedies was denied by the supreme administrative court (Conseil d’Etat). In July 2016, the Conseil d’Etat confirmed the decision of the FCA in part, but directed the FCA to conduct further analysis as to certain assets and to consider further remedies with respect to the assets that were previously identified for divestiture. The Company is in the process of preparing an appropriate filing addressing these issues for submission to the FCA. Although we cannot predict the final results of this matter, we believe that the final outcome of the proceedings will not have a material effect on our financial position, results of operations or cash flows. Other Acquisitions During Fiscal 2016, Flaga and AvantiGas acquired several LPG distribution businesses in Austria, Norway and the United Kingdom for $24.1 in cash and AmeriGas OLP acquired several retail propane distribution businesses for $37.6 in cash. During Fiscal 2015, Flaga acquired an LPG distribution business in Hungary for $17.6 in cash and AmeriGas OLP acquired several retail propane distribution businesses for $20.8 in cash. During Fiscal 2014, Energy Services acquired a retail natural gas marketing business located principally in western Pennsylvania from EQT Energy, LLC, an affiliate of EQT Corporation, for $20.0 in cash and AmeriGas OLP acquired several retail propane distribution businesses for $15.7 in cash.

Debt

Debt	12 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Debt	Note 5 — Debt Long-term debt comprises the following at September 30: 2016 2015 AmeriGas Propane: AmeriGas Partners Senior Notes: 5.875% due August 2026 $ 675.0 $ — 5.625% due May 2024 675.0 — 7.00%, due May 2022 980.8 980.8 6.75%, due May 2020 — 550.0 6.50%, due May 2021 — 270.0 6.25%, due August 2019 — 450.0 HOLP Senior Secured Notes, including unamortized premium of $0.7 and $2.5, respectively 15.2 21.0 Other 14.2 11.7 Unamortized debt issuance costs (a) (26.6 ) (21.6 ) Total AmeriGas Propane 2,333.6 2,261.9 UGI International: France SAS Senior Facilities term loan, due through April 2020 674.4 670.7 Flaga variable rate term loan, due October 2020 51.4 — Flaga variable rate term loan, due September 2018 59.1 59.1 Flaga variable rate term loan, due through August 2016 — 29.8 Flaga variable rate term loan, due October 2016 — 21.4 Other 1.4 1.8 Unamortized debt issuance costs (a) (6.7 ) (8.6 ) Total UGI International 779.6 774.2 UGI Utilities: Senior Notes: 4.12%, due September 2046 200.0 — 5.75%, due September 2016 — 175.0 4.98%, due March 2044 175.0 175.0 2.95%, due June 2026 100.0 — 6.21%, due September 2036 100.0 100.0 Medium-Term Notes: 7.37%, due October 2015 — 22.0 5.64%, due December 2015 — 50.0 6.17%, due June 2017 20.0 20.0 7.25%, due November 2017 20.0 20.0 5.67%, due January 2018 20.0 20.0 6.50%, due August 2033 20.0 20.0 6.13%, due October 2034 20.0 20.0 Unamortized debt issuance costs (a) (3.5 ) (2.2 ) Total UGI Utilities 671.5 619.8 Other 10.8 11.5 Total long-term debt 3,795.5 3,667.4 Less: current maturities (29.5 ) (257.9 ) Total long-term debt due after one year $ 3,766.0 $ 3,409.5 (a) Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 2 and Note 3 ). Scheduled principal repayments of long-term debt due in fiscal years 2017 to 2021 follows: 2017 2018 2019 2020 2021 AmeriGas Propane $ 8.5 $ 6.8 $ 6.4 $ 5.7 $ 1.6 UGI Utilities 20.0 40.0 — — — UGI International 0.3 127.3 67.6 539.6 51.5 Other 0.7 0.8 0.8 0.9 0.9 Total $ 29.5 $ 174.9 $ 74.8 $ 546.2 $ 54.0 Short-term borrowings comprise the following at September 30: 2016 2015 Credit Agreements: AmeriGas Propane $ 153.2 $ 68.1 UGI International 0.5 0.6 UGI Utilities 112.5 71.7 Midstream & Marketing — 30.0 Energy Services Receivables Facility 25.5 19.5 Total short-term borrowings $ 291.7 $ 189.9 AmeriGas Propane The AmeriGas Propane Credit Agreement provides for borrowings up to $525 (including a $125 sublimit for letters of credit) and permits AmeriGas OLP to borrow at prevailing interest rates, including the base rate, defined as the higher of the Federal Funds rate plus 0.50% or the agent bank’s prime rate, or at a one-week, or one-, two-, three-, or six-month Eurodollar Rate, as defined in the AmeriGas Propane Credit Agreement, plus a margin. Under the AmeriGas Propane Credit Agreement, the applicable margin on base rate borrowings ranges from 0.50% to 1.50% ; the applicable margin on Eurodollar Rate borrowings ranges from 1.50% to 2.50% ; and the facility fee ranges from 0.30% to 0.45% . The aforementioned margins and facility fees are dependent upon AmeriGas Partners’ ratio of debt to earnings before interest expense, income taxes, depreciation and amortization (each as defined in the AmeriGas Propane Credit Agreement). The AmeriGas Propane Credit Agreement expires in June 2019 . The weighted-average interest rates on AmeriGas OLP borrowings under the AmeriGas Propane Credit Agreement at September 30, 2016 and 2015 , were 2.79% and 2.20% , respectively. At September 30, 2016 and 2015 , issued and outstanding letters of credit, which reduce available borrowings under this credit agreement, totaled $67.2 and $64.7 , respectively. In June 2016, AmeriGas Partners issued in an underwritten offering $675 principal amount of 5.625% Senior Notes due May 2024 and $675 principal amount of 5.875% Senior Notes due August 2026 (collectively, the “AmeriGas 2016 Senior Notes”). The AmeriGas 2016 Senior Notes rank equally with AmeriGas Partners’ existing outstanding senior notes. The net proceeds from the issuance of the AmeriGas 2016 Senior Notes were used (1) for the early repayment, pursuant to tender offers and notices of redemption, of all of AmeriGas Partners’ 6.50% Senior Notes, 6.75% Senior Notes and 6.25% Senior Notes, having an aggregate principal balance of $1,270.0 plus accrued and unpaid interest and early redemption premiums and (2) for general corporate purposes. During Fiscal 2016, the Partnership recognized a loss of $48.9 associated with the early repayment of these senior notes, primarily comprising $38.9 of early redemption premiums and the write-off of $9.3 of unamortized debt issuance costs. The loss is reflected in “Loss on extinguishments of debt” on the Consolidated Statements of Income. The effective interest rate on the HOLP Notes is 6.75% . The HOLP Senior Secured Notes are collateralized by AmeriGas OLP’s receivables, contracts, equipment, inventory, general intangibles and cash. Restrictive Covenants. The AmeriGas Propane Credit Agreement restricts the incurrence of additional indebtedness and also restricts certain liens, guarantees, investments, loans and advances, payments, mergers, consolidations, asset transfers, transactions with affiliates, sales of assets, acquisitions and other transactions. The AmeriGas Propane Credit Agreement requires that AmeriGas OLP and AmeriGas Partners maintain ratios of total indebtedness to EBITDA, as defined, below certain thresholds. In addition, the Partnership must maintain a minimum ratio of EBITDA to interest expense, as defined and as calculated on a rolling four-quarter basis. Generally, as long as no default exists or would result therefrom, AmeriGas OLP is permitted to make cash distributions not more frequently than quarterly in an amount not to exceed available cash, as defined, for the immediately preceding calendar quarter. The AmeriGas Partners Senior Notes restrict the ability of the Partnership and AmeriGas OLP to, among other things, incur additional indebtedness, make investments, incur liens, issue preferred interests, prepay subordinated indebtedness, and effect mergers, consolidations and sales of assets. Under the AmeriGas Partners Senior Notes Indentures, AmeriGas Partners is generally permitted to make cash distributions equal to available cash, as defined, as of the end of the immediately preceding quarter, if certain conditions are met. At September 30, 2016 , these restrictions did not limit the amount of Available Cash. See Note 14 for the definition of Available Cash included in the Fourth Amended and Restated Agreement of Limited Partnership of AmeriGas Partners, L.P., as amended (“Partnership Agreement”). The HOLP Senior Secured Notes contain restrictive covenants including the maintenance of financial covenants and limitations on the disposition of assets, changes in ownership, additional indebtedness, restrictive payments and the creation of liens. The financial covenants require AmeriGas OLP to maintain a ratio of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined) below certain thresholds and to maintain a minimum ratio of Consolidated EBITDA to Consolidated Interest Expense (as defined). UGI International UGI France On April 30, 2015, France SAS entered into a new five -year Senior Facilities Agreement with a consortium of banks consisting of a €600 variable-rate term loan and a €60 revolving credit facility (“2015 Senior Facilities Agreement”) in anticipation of its then-pending acquisition of Totalgaz, which was consummated on May 29, 2015 (see Note 4 ). The 2015 Senior Facilities Agreement revolving credit facility can be used by each of France SAS’s wholly owned subsidiaries, Antargaz and Finagaz, for up to €30 each. Borrowings under the revolving credit facility bear interest at market rates (one-, two-, three-, or six-month euribor) plus a margin. The margin on credit facility borrowings ranges from 1.45% to 2.55% based upon France SAS’s ratio of consolidated total net debt to EBITDA, as defined in the 2015 Senior Facilities Agreement. The 2015 Senior Facilities Agreement expires in April 2020 . On May 29, 2015, France SAS borrowed €600 ( $659.6 ) under the 2015 Senior Facilities Agreement. The term loan proceeds were used (1) to fund a portion of the Totalgaz Acquisition, including related fees and expenses; (2) to make a capital contribution from France SAS to its wholly owned subsidiary, AGZ Holding, to prepay €342 principal amount, plus accrued interest, outstanding under Antargaz’ 2011 Senior Facilities Agreement due March 2016 (the “2011 Senior Facilities Agreement”); (3) to settle Antargaz’ existing pay-fixed, receive-variable interest rate swaps associated with the 2011 Senior Facilities Agreement; and (4) for general corporate purposes. Principal amounts outstanding under the 2015 Senior Facilities Agreement term loan are due as follows: €60 due April 30, 2018; €60 due April 30, 2019; and €480 due April 30, 2020. As a result of prepaying the term loan outstanding under the 2011 Senior Facilities Agreement and concurrently settling the associated pay-fixed, receive-variable interest rate swaps, we recorded a pre-tax loss of $10.3 comprising a $9.0 loss on interest rate swaps and the write-off of $1.3 of debt issuance costs. These amounts are included in interest expense on the Fiscal 2015 Consolidated Statement of Income. Borrowings under the 2015 Senior Facilities Agreement €600 term loan bear interest at rates per annum comprising the aggregate of the applicable margin and the associated euribor rate, which euribor rate has a floor of zero . The margin on term loan borrowings (which ranges from 1.60% to 2.70% ) are dependent upon the ratio of France SAS’ consolidated total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement. At September 30, 2016, such margin was 1.90% . France SAS has entered into pay-fixed, receive-variable interest rate swaps through April 30, 2019, to fix the underlying euribor rate on term loan borrowings at 0.18% . At September 30, 2016 and 2015, the effective interest rate on the 2015 Senior Facilities Agreement term loan was approximately 2.10% and 2.70% , respectively. Flaga In October 2015, Flaga entered into a €100.8 Credit Facility Agreement (“Flaga Credit Facility Agreement”) with a bank. The Flaga Credit Facility Agreement includes a €25 multi-currency revolving credit facility, a €5 overdraft facility, a €25 guarantee facility and a €45.8 term loan facility. Concurrent with entering into the Flaga Credit Facility Agreement, Flaga terminated its then-existing €46 multi-currency working capital facility. The Flaga Credit Facility Agreement revolving credit facility borrowings bear interest at market rates (generally one, three or six-month euribor rates) plus margins. The margins on revolving facility borrowings, which range from 1.45% to 3.65% , are based upon the actual currency borrowed and certain consolidated equity, return on assets and debt to EBITDA ratios, as defined in the Flaga Credit Facility Agreement. Facility fees on the unused amount of the revolving credit facility are 30% of the lowest applicable margin. The Flaga Credit Facility Agreement terminates in October 2020 . In October 2015, borrowings under the Flaga Credit Facility Agreement’s €45.8 term loan were used to refinance a €19.1 ( $21.4 ) term loan and a €26.7 ( $29.8 ) term loan. The €45.8 ( $51.4 ) term loan bears interest at three-month euribor rates, plus a margin and other fees. The margins and other fees on such borrowings range from 1.20% to 2.60% and are based upon certain consolidated equity, return on assets and debt to EBITDA ratios as defined, as well as fees defined by the local jurisdiction. The effective interest rate on this term loan at September 30, 2016, was 2.11% . At September 30, 2015, the effective interest rates on the €19.1 and €26.7 term loans were 3.40% and 4.21% , respectively. Flaga has entered into pay-fixed, receive-variable interest rate swaps that generally fix the underlying market rate at 0.23% , effective October 2016. Because the cash flows associated with the refinancing of the then-existing term loans were with the same bank, such cash flows have been reflected “net” on the Consolidated Statement of Cash Flows. In September 2015, Flaga terminated its then-existing $52 U.S. dollar-denominated variable-rate term loan due September 2016 and concurrently entered into a $59.1 U.S. dollar-denominated variable-rate term loan with the same bank. The $59.1 term loan matures in September 2018. Because the cash flows from the termination of the $52 term loan and the concurrent issuance of the $59.1 term loan were with the same bank, such cash flows have been reflected “net” in the financing activities section of the Fiscal 2015 Consolidated Statement of Cash Flows. The $59.1 term loan bears interest at a one-month LIBOR rate plus a margin of 1.125% . Flaga has effectively fixed the LIBOR component of the interest rate, and has effectively fixed the U.S. dollar value of the interest and principal payments payable under the $59.1 term loan, by entering into a cross-currency swap arrangement with a bank. At September 30, 2016 and 2015, the effective interest rate on the $59.1 term loan was 0.87% . Restrictive Covenants and Guarantees. The 2015 Senior Facilities Agreement restricts the ability of France SAS to, among other things, incur additional indebtedness, make investments, incur liens, and effect mergers, consolidations and sales of assets, and requires France SAS and its consolidated subsidiaries to maintain a ratio of total net debt to EBITDA, each as defined in the 2015 Senior Facilities Agreement, that shall not exceed 3.50 to 1.00 as determined semiannually. France SAS will generally be permitted to make restricted payments, such as dividends, if no event of default exists or would exist upon payment of such dividend. Borrowings under the Flaga Credit Facility Agreement are guaranteed by UGI. The Flaga term loans and associated interest rate and cross-currency swap agreements are guaranteed by UGI. In addition, under certain conditions regarding changes in certain financial ratios of UGI, the lending banks may accelerate repayment of the debt. UGI Utilities The UGI Utilities Credit Agreement provides for borrowings up to $300 and includes a $100 sublimit for letters of credit. Under the UGI Utilities Credit Agreement, UGI Utilities may borrow at various prevailing market interest rates, including LIBOR and the banks’ prime rate, plus a margin. The margin on such borrowings ranges from 0.0% to 1.75% and is based upon the credit ratings of certain indebtedness of UGI Utilities. The UGI Utilities Credit Agreement is scheduled to expire in March 2020 . The weighted-average interest rates on UGI Utilities borrowings under the UGI Utilities Credit Agreement at September 30, 2016 and 2015 , were 1.42% and 1.07% , respectively. At September 30, 2016 and 2015 , issued and outstanding letters of credit, which reduce available borrowings under this credit agreement, totaled $2.0 and $2.0 , respectively. In April 2016, UGI Utilities entered into a Note Purchase Agreement (the “2016 Note Purchase Agreement”) with a consortium of lenders. Pursuant to the 2016 Note Purchase Agreement, UGI Utilities issued $100 aggregate principal amount of 2.95% Senior Notes due June 2026 and $200 aggregate principal amount of 4.12% Senior Notes due September 2046 in June 2016 and September 2016, respectively. In October 2016, UGI Utilities issued $100 aggregate principal amount of 4.12% Senior Notes due October 2046. The net proceeds of the issuance of these senior notes were used (1) to repay UGI Utilities’ maturing 5.75% Senior Notes, 7.37% Medium-term Notes and 5.64% Medium-term Notes; (2) to provide additional financing for UGI Utilities’ infrastructure replacement and betterment capital program and the information technology initiatives; and (3) for general corporate purposes. The UGI Utilities Senior Notes are unsecured and rank equally with UGI Utilities’ existing outstanding senior debt. Restrictive Covenants. The UGI Utilities Credit Agreement requires UGI Utilities not to exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. Certain of UGI Utilities’ Senior Notes include the usual and customary covenants for similar types of notes including, among others, maintenance of existence, payment of taxes when due, compliance with laws and maintenance of insurance. These Senior Notes also contain restrictive and financial covenants including a requirement that UGI Utilities not exceed a ratio of Consolidated Debt to Consolidated Total Capital, as defined, of 0.65 to 1.00. Energy Services In February 2016, Energy Services, LLC entered into a Second Amended and Restated Credit Agreement (the "Energy Services Credit Agreement"), as borrower, with a group of lenders providing for borrowings up to $240 , including a $50 sublimit for letters of credit. The Energy Services Credit Agreement can be used for general corporate purposes of Energy Services, LLC and its subsidiaries. Energy Services, LLC may not pay a dividend unless, after giving effect to such dividend payment, the ratio of Consolidated Total Indebtedness to EBITDA, each as defined in the Energy Services Credit Agreement, does not exceed 3.00 to 1.00. Borrowings under the Energy Services Credit Agreement bear interest at either (i) the Alternate Base Rate plus a margin or (ii) a rate derived from LIBOR (“Adjusted LIBOR”) plus a margin. The Alternate Base Rate (as defined in the Energy Services Credit Agreement) is the highest of (a) the prime rate, (b) the federal funds rate plus 0.50% , and (c) Adjusted LIBOR plus 1.00% . The margin on such borrowings is currently 2.25% . There were no borrowings outstanding under the Energy Services Credit Agreement at September 30, 2016. The weighted-average interest rate on borrowings outstanding under Energy Services, LLC’s prior credit agreement at September 30, 2015 was 2.75% . The Energy Services Credit Agreement is guaranteed by certain subsidiaries of Energy Services, LLC. Restrictive Covenants. The Energy Services Credit Agreement requires that Energy Services, LLC and subsidiaries not exceed a ratio of total indebtedness to EBITDA, as defined, of 3.50 to 1.00, and maintain a minimum ratio of EBITDA to interest expense, as defined, of 3.50 to 1.00. Accounts Receivable Securitization Facility. Energy Services, LLC has a receivables purchase facility (“Receivables Facility”) with an issuer of receivables-backed commercial paper currently scheduled to expire in October 2017. The Receivables Facility, as amended, provides Energy Services, LLC with the ability to borrow up to $150 of eligible receivables during the period November to April, and up to $75 of eligible receivables during the period May to October. Energy Services, LLC uses the Receivables Facility to fund working capital, margin calls under commodity futures contracts, capital expenditures, dividends and for general corporate purposes. Under the Receivables Facility, Energy Services, LLC transfers, on an ongoing basis and without recourse, its trade accounts receivable to its wholly owned, special purpose subsidiary, Energy Services Funding Corporation (“ESFC”), which is consolidated for financial statement purposes. ESFC, in turn, has sold and, subject to certain conditions, may from time to time sell, an undivided interest in some or all of the receivables to a major bank. Amounts sold to the bank are reflected as short-term borrowings on the Consolidated Balance Sheets. ESFC was created and has been structured to isolate its assets from creditors of Energy Services, LLC and its affiliates, including UGI. Trade receivables sold to the bank remain on the Company’s balance sheet and the Company reflects a liability equal to the amount advanced by the bank. The Company records interest expense on amounts owed to the bank. Energy Services continues to service, administer and collect trade receivables on behalf of the bank, as applicable. Losses on sales of receivables to the bank during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , which amounts are included in interest expense on the Consolidated Statements of Income, were not material. Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , as well as the balance of ESFC trade receivables at September 30, 2016 , 2015 and 2014 follows: 2016 2015 2014 Trade receivables transferred to ESFC during the year $ 756.4 $ 1,037.8 $ 1,260.6 ESFC trade receivables sold to the bank during the year 204.0 306.5 354.0 ESFC trade receivables - end of year (a) 35.7 44.1 46.4 (a) The amounts of ESFC trade receivables sold to the bank are reflected as short-term borrowings on the Consolidated Balance Sheets. Restricted Net Assets At September 30, 2016 , the amount of net assets of UGI’s consolidated subsidiaries that was restricted from transfer to UGI under debt agreements, subsidiary partnership agreements and regulatory requirements under foreign laws totaled approximately $1,600 .

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 6 — Income Taxes Income before income taxes comprises the following: 2016 2015 2014 Domestic $ 518.9 $ 552.3 $ 699.2 Foreign 191.1 39.5 68.6 Total income before income taxes $ 710.0 $ 591.8 $ 767.8 The provisions for income taxes consist of the following: 2016 2015 2014 Current expense (benefit): Federal $ 44.2 $ 97.1 $ 102.4 State 20.9 32.2 30.7 Foreign 78.7 36.0 37.0 Investment tax credit — (1.2 ) (1.6 ) Total current expense 143.8 164.1 168.5 Deferred expense (benefit): Federal 81.2 28.1 61.9 State 1.3 2.9 7.8 Foreign (4.8 ) (17.0 ) (2.7 ) Investment tax credit amortization (0.3 ) (0.3 ) (0.3 ) Total deferred expense 77.4 13.7 66.7 Total income tax expense $ 221.2 $ 177.8 $ 235.2 Federal income taxes for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 are net of foreign tax credits of $25.6 , $63.0 and $12.1 , respectively. A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2016 2015 2014 U.S. federal statutory tax rate 35.0 % 35.0 % 35.0 % Difference in tax rate due to: Noncontrolling interests not subject to tax (6.2 ) (7.9 ) (9.0 ) State income taxes, net of federal benefit 3.0 3.3 3.4 Valuation allowance adjustments (0.9 ) 0.8 — Effects of foreign operations 0.6 0.2 1.0 Other, net (0.3 ) (1.4 ) 0.2 Effective tax rate 31.2 % 30.0 % 30.6 % In December 2013, the French Parliament approved the Finance Bill for 2014 and amended the Finance Bill for 2013 (collectively, the “Finance Bills”). Among other things, the Finance Bills limit UGI France’s ability to deduct certain interest expense for income tax purposes and temporarily increase the corporate surtax rate for a period of two years . Based upon our review of the Finance Bills and interpretive guidance, provisions of the Finance Bills associated with the deductibility of certain interest expense at UGI France apply retroactively to such interest expense incurred during Fiscal 2013. In December 2013, the Company recorded additional income taxes of $5.7 to reflect the effects of the retroactive provisions of the Finance Bills, which are included in effects of foreign operations in the effective tax rate table above. Earnings of the Company’s foreign subsidiaries are generally subject to U.S. taxation upon repatriation to the U.S. and the Company’s tax provisions reflect the related incremental U.S. tax except for certain foreign subsidiaries whose unremitted earnings are considered to be indefinitely reinvested. At September 30, 2016 , unremitted earnings of foreign subsidiaries of approximately $81.7 were deemed to be indefinitely reinvested. No deferred tax liability has been recognized with regard to the remittance of such earnings. Because of the availability of U.S. foreign tax credits, it is likely no U.S. tax would be due if such earnings were repatriated. Pennsylvania utility ratemaking practice permits the flow through to ratepayers of state tax benefits resulting from accelerated tax depreciation. For Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the beneficial effects of state tax flow through of accelerated depreciation reduced income tax expense by $1.3 , $1.5 and $2.0 , respectively. Deferred tax liabilities (assets) comprise the following at September 30: 2016 2015 Excess book basis over tax basis of property, plant and equipment $ 873.9 $ 798.4 Investment in AmeriGas Partners 323.2 321.4 Intangible assets and goodwill 87.1 87.1 Utility regulatory assets 148.3 117.4 Other 11.9 8.9 Gross deferred tax liabilities 1,444.4 1,333.2 Pension plan liabilities (79.7 ) (59.1 ) Employee-related benefits (63.1 ) (57.6 ) Operating loss carryforwards (31.5 ) (32.5 ) Foreign tax credit carryforwards (105.1 ) (113.8 ) Utility regulatory liabilities (13.9 ) (24.0 ) Derivative instruments (14.7 ) (11.4 ) Utility environmental liabilities (22.8 ) (6.0 ) Other (28.3 ) (17.4 ) Gross deferred tax assets (359.1 ) (321.8 ) Deferred tax assets valuation allowance 114.3 131.3 Net deferred tax liabilities $ 1,199.6 $ 1,142.7 At September 30, 2016 , foreign net operating loss carryforwards principally relating to Flaga, UGI International Holdings BV and certain operations of UGI France totaled $52.4 , $2.5 and $21.4 , respectively, with no expiration dates. We have state net operating loss carryforwards primarily relating to certain subsidiaries which approximate $179.4 and expire through 2036 . We also have operating loss carryforwards of $22.4 for certain operations of AmeriGas Propane that expire through 2036 . At September 30, 2016 , deferred tax assets relating to operating loss carryforwards include $9.7 for Flaga, $7.6 for UGI France, $0.6 for UGI International Holdings BV, $8.6 for AmeriGas Propane and $5.0 for certain other subsidiaries. In 2016, the Company reversed valuation allowances associated with certain state tax net operating loss carryforwards of approximately $5.5 as a result of certain tax planning strategies that were related to legal entity classification. A valuation allowance of $0.2 remains for deferred tax assets related to other state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries because, on a state reportable basis, it is more likely than not that these assets will expire unused. A valuation allowance of $9.0 also exists for deferred tax assets related to certain operations of UGI France, Flaga and UGI International Holdings BV. Operating activities and tax deductions related to the exercise of non-qualified stock options contributed to the state net operating losses disclosed above. We first recognize the utilization of state net operating losses from operations (which exclude the impact of tax deductions for exercises of non-qualified stock options) to reduce income tax expense. Then, to the extent state net operating loss carryforwards, if realized, relate to non-qualified stock option deductions, the resulting benefits are credited to UGI Corporation stockholders’ equity. The table of deferred tax assets and liabilities do not include $7.7 for Fiscal 2016 and $6.5 for Fiscal 2015 of deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions. We have foreign tax credit carryforwards of approximately $105.1 expiring through 2026 resulting from the actual and planned repatriation of UGI France’s accumulated earnings since acquisition which are includable in U.S. taxable income. Because we expect that these credits will expire unused, a valuation allowance has been provided for the entire foreign tax credit carryforward amount. The valuation allowance for all deferred tax assets decreased by $17.0 in Fiscal 2016 due to decreases in unusable foreign tax credits of $8.8 , foreign operating loss carryforwards of $2.0 and unusable state operating loss tax benefits of $6.2 . We conduct business and file tax returns in the U.S., numerous states, local jurisdictions and in France and certain other European countries. Our U.S. federal income tax returns are settled through the 2012 tax year, our French tax returns are settled through the 2012 tax year, our Austrian tax returns are settled through 2013 and our other European tax returns are effectively settled for various years from 2007 to 2014. State and other income tax returns in the U.S. are generally subject to examination for a period of three to five years after the filing of the respective returns. As of September 30, 2016 , we have unrecognized income tax benefits totaling $7.2 including related accrued interest of $0.3 . If these unrecognized tax benefits were subsequently recognized, $5.8 would be recorded as a benefit to income taxes on the Consolidated Statement of Income and, therefore, would impact the reported effective tax rate. Generally, a net reduction in unrecognized tax benefits could occur because of the expiration of the statute of limitations in certain jurisdictions or as a result of settlements with tax authorities. There is no material change expected in unrecognized tax benefits and related interest in the next twelve months. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2016 2015 2014 Unrecognized tax benefits - beginning of year $ 3.2 $ 2.4 $ 3.4 Additions for tax positions of the current year 2.2 0.9 0.7 Additions for tax positions taken in prior years 2.3 0.5 — Settlements with tax authorities/statute lapses (0.5 ) (0.6 ) (1.7 ) Unrecognized tax benefits - end of year $ 7.2 $ 3.2 $ 2.4

Employee Retirement Plans

Employee Retirement Plans	12 Months Ended
	Sep. 30, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Employee Retirement Plans	Note 7 — Employee Retirement Plans Defined Benefit Pension and Other Postretirement Plans In the U.S., we sponsor a defined benefit pension plan for employees hired prior to January 1, 2009, of UGI, UGI Utilities, PNG, CPG and certain of UGI’s other domestic wholly owned subsidiaries (“U.S. Pension Plan”). U.S. Pension Plan benefits are based on years of service, age and employee compensation. We also provide postretirement health care benefits to certain retirees and postretirement life insurance benefits to nearly all U.S. active and retired employees. In addition, UGI France employees are covered by certain defined benefit pension and postretirement plans. Although the disclosures in the tables below include amounts related to the UGI France plans, such amounts are not material. The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the UGI France pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2016 and 2015 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation. Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Change in benefit obligations: Benefit obligations — beginning of year $ 614.7 $ 573.6 $ 25.4 $ 21.3 Service cost 10.1 10.0 0.7 0.7 Interest cost 26.8 25.5 0.9 0.8 Actuarial loss (gain) 83.3 14.4 6.6 (2.7 ) Plan amendments — (0.6 ) (1.5 ) — Curtailment (1.4 ) (0.8 ) (0.3 ) — Totalgaz acquisition — 21.3 — 6.8 Foreign currency 0.1 (4.4 ) — (0.7 ) Benefits paid (25.9 ) (24.3 ) (0.9 ) (0.8 ) Benefit obligations — end of year $ 707.7 $ 614.7 $ 30.9 $ 25.4 Change in plan assets: Fair value of plan assets — beginning of year $ 453.8 $ 459.4 $ 12.5 $ 12.8 Actual gain (loss) on plan assets 53.4 1.1 1.3 (0.1 ) Foreign currency 0.1 (0.4 ) — — Employer contributions 11.4 11.9 0.6 0.6 Totalgaz acquisition — 6.1 — — Benefits paid (25.0 ) (24.3 ) (0.7 ) (0.8 ) Fair value of plan assets — end of year $ 493.7 $ 453.8 $ 13.7 $ 12.5 Funded status of the plans — end of year $ (214.0 ) $ (160.9 ) $ (17.2 ) $ (12.9 ) Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities — included in other noncurrent assets $ — $ — $ 4.1 $ 4.0 Unfunded liabilities — included in other noncurrent liabilities (214.0 ) (160.9 ) (21.3 ) (16.9 ) Net amount recognized $ (214.0 ) $ (160.9 ) $ (17.2 ) $ (12.9 ) Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): Prior service credit $ (0.6 ) $ (0.6 ) $ (1.5 ) $ (0.1 ) Net actuarial loss 31.4 22.5 3.8 0.7 Total $ 30.8 $ 21.9 $ 2.3 $ 0.6 Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (credit) $ 1.2 $ 1.6 $ (2.2 ) $ (2.9 ) Net actuarial loss 181.0 138.4 2.4 2.3 Total $ 182.2 $ 140.0 $ 0.2 $ (0.6 ) In Fiscal 2017 , we estimate that we will amortize approximately $17.0 of net actuarial losses, primarily associated with the U.S. Pension Plan, and $0.5 of net prior service credits from UGI stockholders’ equity and regulatory assets into retiree benefit cost. Actuarial assumptions for our U.S. plans are described below. Assumptions for the UGI France plans are based upon market conditions in France, Belgium and the Netherlands. The discount rate assumption was determined by selecting a hypothetical portfolio of high quality corporate bonds appropriate to provide for the projected benefit payments of the plans. The discount rate was then developed as the single rate that equates the market value of the bonds purchased to the discounted value of the plans’ benefit payments. The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below). Pension Plan Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Weighted-average assumptions: Discount rate - benefit obligations 3.80 % 4.60 % 4.60 % 3.80 % 4.70 % 4.60 % Discount rate - benefit cost 4.60 % 4.60 % 5.20 % 4.70 % 4.60 % 5.10% - 5.40% Expected return on plan assets 7.55 % 7.75 % 7.75 % 5.00 % 5.00 % 5.00 % Rate of increase in salary levels 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % The ABOs for the U.S. Pension Plan were $601.3 and $523.7 as of September 30, 2016 and 2015 , respectively. Net periodic pension expense and other postretirement benefit cost includes the following components: Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Service cost $ 10.1 $ 10.0 $ 9.4 $ 0.7 $ 0.7 $ 0.5 Interest cost 26.8 25.5 26.1 0.9 0.8 0.9 Expected return on assets (32.4 ) (32.2 ) (29.7 ) (0.6 ) (0.6 ) (0.6 ) Curtailment gain (1.2 ) (0.8 ) — — — — Amortization of: Prior service cost (benefit) 0.3 0.3 0.3 (0.6 ) (0.5 ) (0.5 ) Actuarial loss 10.9 10.0 7.7 — 0.1 — Net benefit cost 14.5 12.8 13.8 0.4 0.5 0.3 Change in associated regulatory liabilities — — — 1.0 3.7 3.7 Net benefit cost after change in regulatory liabilities $ 14.5 $ 12.8 $ 13.8 $ 1.4 $ 4.2 $ 4.0 The U.S. Pension Plan’s assets are held in trust and consist principally of publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. It is our general policy to fund amounts for U.S. Pension Plan benefits equal to at least the minimum required contribution set forth in applicable employee benefit laws. From time to time we may, at our discretion, contribute additional amounts. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , we made cash contributions to the U.S. Pension Plan of $9.9 , $11.1 and $19.2 respectively. The minimum required contributions in Fiscal 2017 are not expected to be material. UGI Utilities has established a Voluntary Employees’ Beneficiary Association (“VEBA”) trust to pay retiree health care and life insurance benefits by depositing into the VEBA the annual amount of postretirement benefits costs, if any, determined under GAAP. The difference between such amount and amounts included in UGI Gas’ and Electric Utility’s rates is deferred for future recovery from, or refund to, ratepayers. Any required contributions to the VEBA during Fiscal 2017 are not expected to be material. Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2017 $ 28.7 $ 1.1 Fiscal 2018 $ 28.7 $ 1.1 Fiscal 2019 $ 30.0 $ 1.1 Fiscal 2020 $ 36.3 $ 1.1 Fiscal 2021 $ 39.5 $ 1.1 Fiscal 2022 - 2026 $ 189.1 $ 5.5 The assumed domestic health care cost trend rates at September 30 are as follows: 2016 2015 Health care cost trend rate assumed for next year 7.25 % 7.5 % Rate to which the cost trend rate is assumed to decline (ultimate trend rate) 5.0 % 5.0 % Fiscal year that the rate reaches the ultimate trend rate 2026 2026 A one percentage point change in the assumed health care cost trend rate would not have a material impact on the Fiscal 2016 other postretirement benefit cost or September 30, 2016 , other postretirement benefit ABO. We also sponsor unfunded and non-qualified supplemental executive defined benefit retirement plans (“Supplemental Defined Benefit Plans”). At September 30, 2016 and 2015 , the PBOs of these plans, including obligations for amounts held in grantor trusts, were $47.4 and $40.1 , respectively. We recorded pre-tax costs for these plans of $2.6 in Fiscal 2016 , $2.3 in Fiscal 2015 and $2.6 in Fiscal 2014 . These costs are not included in the tables above. Amounts recorded in UGI’s stockholders’ equity for these plans include pre-tax losses of $13.0 and $10.1 at September 30, 2016 and 2015 , respectively, principally representing unrecognized actuarial losses. We expect to amortize approximately $1.2 of such pre-tax actuarial losses into retiree benefit cost in Fiscal 2017 . During Fiscal 2016 and 2014 the Company made payments with respect to the Supplemental Defined Benefit Plans totaling $0.4 and $0.3 , respectively. There were no such payments made in Fiscal 2015. The total fair value of the grantor trust investment assets associated with the Supplemental Defined Benefit Plans, which are included in other assets on the Consolidated Balance Sheets, totaled $28.4 and $26.1 at September 30, 2016 and 2015 , respectively. U.S. Pension Plan and VEBA Assets The assets of the U.S. Pension Plan and the VEBA are held in trust. The investment policies and asset allocation strategies for the assets in these trusts are determined by an investment committee comprising officers of UGI and UGI Utilities. The overall investment objective of the U.S. Pension Plan and the VEBA is to achieve the best long-term rates of return within prudent and reasonable levels of risk. To achieve the stated objective, investments are made principally in publicly traded, diversified equity and fixed income mutual funds and, to a much lesser extent, smallcap common stocks and UGI Common Stock. Assets associated with the UGI France plans are excluded from the disclosures in the tables below as such assets are not material. The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows: U.S. Pension Plan Actual Target Asset Allocation Permitted Range 2016 2015 Equity investments: Domestic 54.1 % 56.2 % 52.5 % 40.0% - 65.0% International 10.2 % 10.2 % 12.5 % 7.5% - 17.5% Total 64.3 % 66.4 % 65.0 % 60.0% - 70.0% Fixed income funds & cash equivalents 35.7 % 33.6 % 35.0 % 30.0% - 40.0% Total 100.0 % 100.0 % 100.0 % VEBA Actual Target Asset Allocation Permitted Range 2016 2015 Domestic equity investments 69.9 % 67.4 % 65.0 % 60.0% - 70.0% Fixed income funds & cash equivalents 30.1 % 32.6 % 35.0 % 30.0% - 40.0% Total 100.0 % 100.0 % 100.0 % Domestic equity investments include investments in large-cap mutual funds indexed to the S&P 500, actively managed mid- and small-cap mutual funds, and a separately managed account comprising small-cap common stocks. Investments in international equity mutual funds seek to track performance of companies primarily in developed markets. The fixed income investments comprise investments designed to match the performance and duration of the Barclays U.S. Aggregate Index. According to statute, the aggregate holdings of all qualifying employer securities may not exceed 10% of the fair value of trust assets at the time of purchase. UGI Common Stock represented 8.0% and 10.1% of U.S. Pension Plan assets at September 30, 2016 and 2015 , respectively. The fair values of U.S. Pension Plan and VEBA trust assets are derived from quoted market prices as substantially all of these instruments have active markets. Cash equivalents are valued at the fund’s unit net asset value as reported by the trustee. The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2016 and 2015 are as follows: U.S. Pension Plan Level 1 Level 2 Level 3 Total September 30, 2016: Domestic equity investments: S&P 500 Index equity mutual funds $ 158.9 $ — $ — $ 158.9 Small and midcap equity mutual funds 43.2 — — 43.2 Smallcap common stocks 11.4 — — 11.4 UGI Corporation Common Stock 37.0 — — 37.0 Total domestic equity investments 250.5 — — 250.5 International index equity mutual funds 47.3 — — 47.3 Fixed income investments: Bond index mutual funds 147.8 — — 147.8 Cash equivalents — 17.8 — 17.8 Total fixed income investments 147.8 17.8 — 165.6 Total $ 445.6 $ 17.8 $ — $ 463.4 September 30, 2015: Domestic equity investments: S&P 500 Index equity mutual funds $ 147.3 $ — $ — $ 147.3 Small and midcap equity mutual funds 40.6 — — 40.6 Smallcap common stocks 10.7 — — 10.7 UGI Corporation Common Stock 43.4 — — 43.4 Total domestic equity investments 242.0 — — 242.0 International index equity mutual funds 43.9 — — 43.9 Fixed income investments: Bond index mutual funds 140.8 — — 140.8 Cash equivalents — 4.1 — 4.1 Total fixed income investments 140.8 4.1 — 144.9 Total $ 426.7 $ 4.1 $ — $ 430.8 VEBA Level 1 Level 2 Level 3 Total September 30, 2016: S&P 500 Index equity mutual fund $ 9.6 $ — $ — $ 9.6 Bond index mutual fund 4.0 — — 4.0 Cash equivalents — 0.1 — 0.1 Total $ 13.6 $ 0.1 $ — $ 13.7 September 30, 2015: S&P 500 Index equity mutual fund $ 8.4 $ — $ — $ 8.4 Bond index mutual fund 3.8 — — 3.8 Cash equivalents — 0.3 — 0.3 Total $ 12.2 $ 0.3 $ — $ 12.5 The expected long-term rates of return on U.S. Pension Plan and VEBA trust assets have been developed using a best estimate of expected returns, volatilities and correlations for each asset class. The estimates are based on historical capital market performance data and future expectations provided by independent consultants. Future expectations are determined by using simulations that provide a wide range of scenarios of future market performance. The market conditions in these simulations consider the long-term relationships between equities and fixed income as well as current market conditions at the start of the simulation. The expected rate begins with a risk-free rate of return with other factors being added such as inflation, duration, credit spreads and equity risk premiums. The rates of return derived from this process are applied to our target asset allocation to develop a reasonable return assumption. Defined Contribution Plans We sponsor 401(k) savings plans for eligible employees of UGI and certain of UGI’s domestic subsidiaries. Generally, participants in these plans may contribute a portion of their compensation on either a before-tax basis, or on both a before-tax and after-tax basis. These plans also provide for employer matching contributions at various rates. The cost of benefits under the savings plans totaled $14.3 in Fiscal 2016 , $15.2 in Fiscal 2015 and $14.7 in Fiscal 2014 . The Company also sponsors certain nonqualified supplemental defined contribution executive retirement plans. These plans generally provide supplemental benefits to certain executives that would otherwise be provided under retirement plans but are prohibited due to limitations imposed by the Internal Revenue Code. The Company makes payments to self-directed grantor trusts with respect to these supplemental defined contribution plans. Such payments during Fiscal 2016 , Fiscal 2015 or Fiscal 2014 were not material. At September 30, 2016 and 2015 , the total fair values of the grantor trust investment assets, which amounts are included in other noncurrent assets on the Consolidated Balance Sheets, were $4.6 and $4.2 , respectively.

Utility Regulatory Assets and L

Utility Regulatory Assets and Liabilities and Regulatory Matters	12 Months Ended
	Sep. 30, 2016
Regulated Operations [Abstract]
Utility Regulatory Assets and Liabilities and Regulatory Matters	Note 8 — Utility Regulatory Assets and Liabilities and Regulatory Matters The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Consolidated Balance Sheets at September 30: 2016 2015 Regulatory assets: Income taxes recoverable $ 115.7 $ 115.9 Underfunded pension and postretirement plans 183.1 140.8 Environmental costs (a) 59.4 20.0 Removal costs, net 27.9 21.2 Other 9.0 6.3 Total regulatory assets $ 395.1 $ 304.2 Regulatory liabilities (b): Postretirement benefit overcollections $ 17.5 $ 20.0 Deferred fuel and power refunds 22.3 36.6 State income tax benefits — distribution system repairs 15.1 13.3 Other 0.7 1.1 Total regulatory liabilities $ 55.6 $ 71.0 (a) Balance at September 30, 2016, includes amounts associated with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 15 ). (b) Regulatory liabilities are recorded in other current and other noncurrent liabilities on the Consolidated Balance Sheets. Other than removal costs, UGI Utilities does not recover a rate of return on the regulatory assets included in the table above. Income taxes recoverable . This regulatory asset is the result of recording deferred tax liabilities pertaining to temporary tax differences principally as a result of the pass through to ratepayers of the tax benefit on accelerated tax depreciation for state income tax purposes, and the flow through of accelerated tax depreciation for federal income tax purposes for certain years prior to 1981. These deferred taxes have been reduced by deferred tax assets pertaining to utility deferred investment tax credits. UGI Utilities has recorded regulatory income tax assets related to these deferred tax liabilities representing future revenues recoverable through the ratemaking process over the average remaining depreciable lives of the associated property ranging from 1 to approximately 65 years. Underfunded pension and other postretirement plans . This regulatory asset represents the portion of net actuarial losses and prior service cost associated with pension and other postretirement benefits which are probable of being recovered through future rates based upon established regulatory practices. These regulatory assets are adjusted annually or more frequently under certain circumstances when the funded status of the plans is recorded in accordance with GAAP. These costs are amortized over the average remaining future service lives of plan participants. Environmental costs . Environmental costs principally represent estimated probable future environmental remediation and investigation costs that UGI Gas, CPG and PNG expect to incur, primarily at Manufactured Gas Plant (“MGP”) sites in Pennsylvania, in conjunction with remediation consent orders and agreements with the Pennsylvania Department of Environmental Protection. Pursuant to base rate orders, UGI Gas, PNG and CPG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. At September 30, 2016 , the period over which UGI Gas, PNG and CPG expect to recover these costs will depend upon future remediation activity. For additional information on environmental costs, see Note 15 . Removal costs, net . This regulatory asset represents costs incurred, net of salvage, associated with the retirement of depreciable utility plant. Consistent with prior ratemaking treatment, UGI Utilities expects to recover these costs over 5 years . Postretirement benefit overcollections . This regulatory liability represents the difference between amounts recovered through rates by UGI Gas and Electric Utility and actual costs incurred in accordance with accounting for postretirement benefits. With respect to UGI Gas, these overcollections will be refunded to customers over a ten -year period beginning October 19, 2016, the date UGI Gas’ Joint Petition pursuant to its January 19, 2016 base rate filing became effective (see “UGI Gas Base Rate Filing” below). With respect to Electric Utility, the difference between the amounts recovered through rates and the actual costs incurred in accordance with accounting for postretirement benefits is being deferred for future rate refund to customers. Deferred fuel and power refunds. Gas Utility’s and Electric Utility’s tariffs contain clauses that permit recovery of all prudently incurred purchased gas and power costs through the application of purchased gas cost (“PGC”) rates in the case of Gas Utility and default service (“DS”) tariffs in the case of Electric Utility. The clauses provide for periodic adjustments to PGC and DS rates for differences between the total amount of purchased gas and electric generation supply costs collected from customers and recoverable costs incurred. Net undercollected costs are classified as a regulatory asset and net overcollections are classified as a regulatory liability. Gas Utility uses derivative instruments to reduce volatility in the cost of gas it purchases for firm- residential, commercial and industrial (“retail core-market”) customers. Realized and unrealized gains or losses on natural gas derivative instruments are included in deferred fuel costs or refunds. Net unrealized gains (losses) on such contracts at September 30, 2016 and 2015 were $4.3 and $(3.3) , respectively. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2016 and 2015 , substantially all Electric Utility forward electricity purchase contracts were subject to the NPNS exception (see Note 17 ). In order to reduce volatility associated with a substantial portion of its electric transmission congestion costs, Electric Utility obtains financial transmission rights (“FTRs”). FTRs are derivative instruments that entitle the holder to receive compensation for electricity transmission congestion charges when there is insufficient electricity transmission capacity on the electric transmission grid. Because Electric Utility is entitled to fully recover its DS costs, realized and unrealized gains or losses on FTRs are included in deferred fuel and power costs or deferred fuel and power refunds. Unrealized gains or losses on FTRs at September 30, 2016 and 2015 , were not material. State income tax benefits — distribution system repairs. This regulatory liability represents Pennsylvania state income tax benefits, net of federal benefit, resulting from the deduction for income tax purposes of repair and maintenance costs associated with Gas Utility or Electric Utility assets which are capitalized for regulatory and GAAP reporting. The tax benefits associated with these repair and maintenance deductions will be reflected as a reduction to income tax expense over the remaining tax lives of the related book assets. Other . Other regulatory assets comprise a number of deferred items including, among others, a portion of preliminary stage information technology costs, energy efficiency conservation costs and rate case expenses. At September 30, 2016 , UGI Utilities expects to recover these costs over periods of approximately 1 to 20 years. Other Regulatory Matters Preliminary Stage Information Technology Costs. During the second quarter of Fiscal 2016, we determined that certain preliminary project stage costs associated with an ongoing information technology project at UGI Utilities were probable of future recovery in rates in accordance with GAAP related to regulated entities. As a result, during the second quarter of Fiscal 2016, we capitalized $5.8 of such project costs ( $5.4 of which had been expensed prior to Fiscal 2016) and recorded associated increases to utility property, plant and equipment ( $2.7 ) and regulatory assets ( $3.1 ). Subsequent to this determination, we continue to capitalize such preliminary stage project costs in accordance with GAAP related to regulated entities. UGI Gas Base Rate Filing. On January 19, 2016, UGI Utilities filed a rate request with the PUC to increase UGI Gas’s annual base operating revenues for residential, commercial and industrial customers by $58.6 . The increased revenues would fund ongoing system improvements and operations necessary to maintain safe and reliable natural gas service. On June 30, 2016, a Joint Petition for Approval of Settlement of all issues providing for a $27.0 UGI Gas annual base distribution rate increase, to be effective October 19, 2016, was filed with the PUC (“Joint Petition”). On October 14, 2016, the PUC approved the Joint Petition with a minor modification which had no effect on the $27.0 base distribution rate increase. The increase became effective on October 19, 2016. Distribution System Improvement Charge. On April 14, 2012, legislation became effective enabling gas and electric utilities in Pennsylvania, under certain circumstances, to recover the cost of eligible capital investment in distribution system infrastructure improvement projects between base rate cases. The charge enabled by the legislation is known as a distribution system improvement charge (“DSIC”). The primary benefit to a company from a DSIC charge is the elimination of regulatory lag, or delayed rate recognition, that occurs under traditional ratemaking relating to qualifying capital expenditures. To be eligible for a DSIC, a utility must have filed a general rate filing within five years of its petition seeking permission to include a DSIC in its tariff, and not exceed certain earnings tests. Absent PUC permission, the DSIC is capped at five percent of the amount billed to customers. PNG and CPG received PUC approval on a DSIC tariff, initially set at zero , in 2014. PNG and CPG began charging a DSIC at a rate other than zero beginning on April 1, 2015 and April 1, 2016, respectively. In March 2016, PNG and CPG filed petitions, seeking approval to increase the maximum allowable DSIC from five percent to ten percent of billed distribution revenues. To date, no action has been taken by the PUC on either of these petitions. The Company cannot predict the timing or outcome of these petitions. On November 9, 2016, UGI Gas received PUC approval to establish a DSIC tariff mechanism effective January 1, 2017. Revenue collected pursuant to the mechanism will be subject to refund and recoupment based on the PUC’s final resolution of certain matters set aside for hearing before an administrative law judge. To commence recovery of revenue under the mechanism, UGI Gas must first place into service a threshold level of DSIC-eligible plant agreed upon in the settlement of its recent base rate case. Achievement of that threshold is not likely to occur prior to September 30, 2017.

Inventories

Inventories	12 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Inventories	Note 9 — Inventories Inventories comprise the following at September 30: 2016 2015 Non-utility LPG and natural gas $ 129.8 $ 140.7 Gas Utility natural gas 29.2 37.5 Materials, supplies and other 51.3 61.7 Total inventories $ 210.3 $ 239.9 At September 30, 2016 , UGI Utilities was a party to three principal storage contract administrative agreements (“SCAAs”) having terms of three years. Pursuant to SCAAs, UGI Utilities has, among other things, released certain storage and transportation contracts for the terms of the SCAAs. UGI Utilities also transferred certain associated storage inventories upon commencement of the SCAAs, will receive a transfer of storage inventories at the end of the SCAAs, and makes payments associated with refilling storage inventories during the terms of the SCAAs. The historical cost of natural gas storage inventories released under the SCAAs, which represents a portion of Gas Utility’s total natural gas storage inventories, and any exchange receivable (representing amounts of natural gas inventories used by the other parties to the agreement but not yet replenished for which UGI Utilities has the rights), are included in the caption “Gas Utility natural gas” in the table above. As of September 30, 2016 , UGI Utilities has SCAAs with Energy Services and a non-affiliate. The carrying value of gas storage inventories released under the SCAAs with the non-affiliate at September 30, 2016 and 2015 , comprising 3.5 billion cubic feet (“bcf”) and 4.0 bcf of natural gas, was $7.6 and $9.8 , respectively.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Sep. 30, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 10 — Property, Plant and Equipment Property, plant and equipment comprise the following at September 30: 2016 2015 Utilities: Distribution $ 2,634.2 $ 2,458.1 Transmission 93.5 90.0 General and other, including work in process 271.2 205.4 Total Utilities 2,998.9 2,753.5 Non-utility: Land 169.9 174.9 Buildings and improvements 382.2 391.4 Transportation equipment 301.7 327.9 Equipment, primarily cylinders and tanks 3,421.5 3,268.1 Electric generation 309.4 305.7 Pipeline and related assets 235.8 233.5 Other, including work in process 525.9 374.1 Total non-utility 5,346.4 5,075.6 Total property, plant and equipment $ 8,345.3 $ 7,829.1

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 11 — Goodwill and Intangible Assets Changes in the carrying amount of goodwill by reportable segment are as follows: UGI International AmeriGas Propane UGI Utilities Energy Services (a) UGI France Flaga & Other Total Balance September 30, 2014 $ 1,945.1 $ 182.1 $ 12.6 $ 601.2 $ 92.4 $ 2,833.4 Acquisitions 10.9 — — 186.2 2.9 200.0 Dispositions — — (1.0 ) — — (1.0 ) Foreign currency translation — — — (66.0 ) (13.0 ) (79.0 ) Balance September 30, 2015 1,956.0 182.1 11.6 721.4 82.3 2,953.4 Acquisitions 24.2 — — — 16.9 41.1 Dispositions — — — — (1.6 ) (1.6 ) Purchase price adjustments (1.9 ) — — (2.4 ) (0.2 ) (4.5 ) Foreign currency translation — — — 4.2 (3.6 ) 0.6 Balance September 30, 2016 $ 1,978.3 $ 182.1 $ 11.6 $ 723.2 $ 93.8 $ 2,989.0 (a) Prior year amounts were restated to reflect the current-year changes in the presentation of our Energy Services reportable segment (see Note 21). Intangible assets comprise the following at September 30: 2016 2015 Customer relationships, noncompete agreements and other $ 773.5 $ 761.1 Trademarks and tradenames (not subject to amortization) 131.6 131.4 Gross carrying amount 905.1 892.5 Accumulated amortization (324.8 ) (282.4 ) Intangible assets, net $ 580.3 $ 610.1 Amortization expense of intangible assets was $54.3 , $52.0 and $48.2 for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. Estimated amortization expense of intangible assets during the next five fiscal years is as follows: Fiscal 2017 — $48.6 ; Fiscal 2018 — $47.1 ; Fiscal 2019 — $45.4 ; Fiscal 2020 — $44.1 ; Fiscal 2021 — $42.2 .

Series Preferred Stock

Series Preferred Stock	12 Months Ended
	Sep. 30, 2016
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Series Preferred Stock	Note 12 — Series Preferred Stock UGI has 10,000,000 shares of UGI Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. We had no shares of UGI Series Preferred Stock outstanding at September 30, 2016 or 2015 . UGI Utilities has 2,000,000 shares of UGI Utilities Series Preferred Stock authorized for issuance, including both series subject to and series not subject to mandatory redemption. At September 30, 2016 and 2015 , there were no shares of UGI Utilities Series Preferred Stock outstanding.

Common Stock and Equity-Based C

Common Stock and Equity-Based Compensation	12 Months Ended
	Sep. 30, 2016
Share-based Compensation [Abstract]
Common Stock and Equity-Based Compensation	Note 13 — Common Stock and Equity-Based Compensation Common Stock On January 30, 2014, the Company’s Board of Directors authorized the repurchase of up to 15,000,000 shares of UGI Corporation Common Stock over a four -year period. Pursuant to such authorization, during Fiscal 2016 , Fiscal 2015 and Fiscal 2014, the Company purchased and placed in treasury stock 1,250,000 , 1,000,000 and 1,227,654 shares at a total cost of $47.6 , $34.1 and $39.8 , respectively. UGI Common Stock share activity for Fiscal 2014 , Fiscal 2015 and Fiscal 2016 follows: Issued Treasury Outstanding Balance, September 30, 2013 173,675,691 (2,032,404 ) 171,643,287 Issued: Employee and director plans 94,950 2,928,140 3,023,090 Repurchases of common stock — (1,227,654 ) (1,227,654 ) Reacquired common stock - employee and director plans — (1,164,942 ) (1,164,942 ) Balance, September 30, 2014 173,770,641 (1,496,860 ) 172,273,781 Issued: Employee and director plans 36,350 1,155,376 1,191,726 Repurchases of common stock — (1,000,000 ) (1,000,000 ) Reacquired common stock - employee and director plans — (77,004 ) (77,004 ) Balance, September 30, 2015 173,806,991 (1,418,488 ) 172,388,503 Issued: Employee and director plans 87,150 2,355,202 2,442,352 Repurchases of common stock — (1,250,000 ) (1,250,000 ) Reacquired common stock - employee and director plans — (620,406 ) (620,406 ) Balance, September 30, 2016 173,894,141 (933,692 ) 172,960,449 Equity-Based Compensation The Company grants equity-based awards to employees and non-employee directors comprising UGI stock options, UGI Common Stock-based equity instruments and AmeriGas Partners Common Unit-based equity instruments as further described below. We recognized total pre-tax equity-based compensation expense of $23.8 ( $15.4 after-tax), $29.2 ( $18.9 after-tax) and $25.8 ( $16.6 after-tax) in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. UGI Equity-Based Compensation Plans and Awards. On January 24, 2013, the Company’s shareholders approved the UGI Corporation 2013 Omnibus Incentive Compensation Plan (the “2013 OICP”). The 2013 OICP succeeds the UGI Corporation 2004 Omnibus Equity Compensation Plan Amended and Restated as of December 5, 2006 (the “2004 OECP”) for awards granted on or after January 24, 2013. The 2004 OECP will continue in effect but all future grants issued pursuant to it will be solely in the form of options to acquire Common Stock. Under the 2013 OICP, we may grant options to acquire shares of UGI Common Stock, stock appreciation rights (“SARs”), UGI Units (comprising “Stock Units” and “UGI Performance Units”), other equity-based awards and cash to employees and non-employee directors. The exercise price for options may not be less than the fair market value on the grant date. Awards granted under the 2013 OICP may vest immediately or ratably over a period of years, and stock options can be exercised no later than ten years from the grant date. In addition, the 2013 OICP provides that awards of UGI Units may also provide for the crediting of dividend equivalents to participants’ accounts. Except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements. Under the 2004 OECP, we could grant options to acquire shares of UGI Common Stock, UGI Units and other equity-based awards to employees and non-employee directors through January 23, 2013 (except with respect to the granting of stock option awards as previously mentioned). Under the 2004 OECP, the exercise price for stock options could not be less than the fair market value on the grant date. Awards granted under the 2004 OECP could vest immediately or ratably over a period of years, and stock options could be exercised no later than ten years from the date of grant. In addition, the 2004 OECP provided that the awards of UGI Units could include the crediting of dividend equivalents to participants’ accounts. Under the 2013 OICP, awards representing up to 21,750,000 shares of UGI Common Stock may be granted. Dividend equivalents on UGI Unit awards to employees will be paid in cash. Dividend equivalents on non-employee director awards are accumulated in additional Stock Units. UGI Unit awards granted to employees and non-employee directors are settled in shares of Common Stock and cash. Substantially all UGI Unit awards granted to UGI France employees are settled in shares of Common Stock and do not accrue dividend equivalents. With respect to UGI Performance Unit awards, the actual number of shares (or their cash equivalent) ultimately issued, and the actual amount of dividend equivalents paid, is generally dependent upon the achievement of market performance goals and service conditions. It is currently our practice to issue treasury shares to satisfy substantially all option exercises and UGI Unit awards. Stock options may be net exercised whereby shares equal to the option price and the grantee’s minimum applicable payroll tax withholding are withheld from the number of shares payable (“net exercise”). We record shares withheld pursuant to a net exercise as shares reacquired. UGI Stock Option Awards . Stock option transactions under equity-based compensation plans during Fiscal 2014 , Fiscal 2015 and Fiscal 2016 follow: Shares Weighted Average Option Price Total Intrinsic Value Weighted Average Contract Term (Years) Shares under option — September 30, 2013 10,193,952 $ 19.28 $ 69.6 6.8 Granted 1,665,600 $ 27.93 Canceled (86,707 ) $ 22.76 Exercised (2,815,555 ) $ 17.44 $ 37.4 Shares under option — September 30, 2014 8,957,290 $ 21.44 $ 113.3 7.0 Granted 1,336,985 $ 37.70 Canceled (85,365 ) $ 30.45 Exercised (953,533 ) $ 19.10 $ 15.4 Shares under option — September 30, 2015 9,255,377 $ 23.97 $ 104.5 6.6 Granted 1,510,625 $ 34.67 Canceled (84,213 ) $ 34.13 Exercised (2,193,338 ) $ 20.38 $ 40.1 Shares under option — September 30, 2016 8,488,451 $ 26.68 $ 157.6 6.6 Options exercisable — September 30, 2014 5,073,347 $ 19.45 Options exercisable — September 30, 2015 6,050,946 $ 20.74 Options exercisable — September 30, 2016 5,522,370 $ 22.94 $ 123.2 5.6 Options not exercisable — September 30, 2016 2,966,081 $ 33.63 $ 34.4 8.2 Cash received from stock option exercises and associated tax benefits were $27.3 and $14.9 , $16.2 and $5.8 , and $22.2 and $13.0 in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. As of September 30, 2016 , there was $5.3 of unrecognized compensation cost associated with unvested stock options that is expected to be recognized over a weighted-average period of 1.9 years . The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2016 : Range of exercise prices Under $20.00 $20.01 - $25.00 $25.01 - $30.00 $30.01 - $35.00 Over $35.00 Options outstanding at September 30, 2016: Number of options 1,876,551 2,209,352 1,591,195 1,453,584 1,357,769 Weighted average remaining contractual life (in years) 4.1 5.6 7.1 9.1 8.4 Weighted average exercise price $ 18.10 $ 21.58 $ 27.44 $ 33.65 $ 38.46 Options exercisable at September 30, 2016: Number of options 1,876,551 2,073,902 1,033,454 117,050 421,413 Weighted average exercise price $ 18.10 $ 21.56 $ 27.34 $ 32.90 $ 37.73 UGI Stock Option Fair Value Information. The per share weighted-average fair value of stock options granted under our option plans was $4.87 in Fiscal 2016 , $5.47 in Fiscal 2015 and $4.97 in Fiscal 2014 . These amounts were determined using a Black-Scholes option pricing model which values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, expected dividend payments and the risk-free interest rate over the expected life of the option. The expected life of option awards represents the period of time during which option grants are expected to be outstanding and is derived from historical exercise patterns. Expected volatility is based on historical volatility of the price of UGI’s Common Stock. Expected dividend yield is based on historical UGI dividend rates. The risk free interest rate is based on U.S. Treasury bonds with terms comparable to the options in effect on the date of grant. The assumptions we used for valuing option grants during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 are as follows: 2016 2015 2014 Expected life of option 5.75 years 5.75 years 5.75 years Weighted average volatility 19.5% 19.5% 24.3% Weighted average dividend yield 2.6% 2.5% 2.9% Expected volatility 19.3% 19.1% -19.5% 23.7% - 24.4% Expected dividend yield 2.6% 2.5% 2.7% - 2.9% Risk free rate 1.2% - 1.9% 1.5% - 1.8% 1.8% - 2.0% UGI Unit Awards . UGI Stock Unit and UGI Performance Unit awards entitle the grantee to shares of UGI Common Stock or cash once the service condition is met and, with respect to UGI Performance Unit awards, subject to market performance conditions. UGI Performance Unit grant recipients are awarded a target number of Performance Units. The number of UGI Performance Units ultimately paid at the end of the performance period (generally three years) may be higher or lower than the target amount, or even zero, based on UGI’s Total Shareholder Return (“TSR”) percentile rank relative to the Russell Midcap Utility Index, excluding telecommunication companies (“UGI comparator group”). For grants issued on or after January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 25th percentile compared to the UGI comparator group, the employee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25% of the target award; at the 40th percentile, 70% ; at the 50th percentile, 100% ; and at the 90th percentile and above, 200% . For grants issued prior to January 1, 2013, grantees may receive 0% to 200% of the target award granted. For such grants, if UGI’s TSR ranks below the 40th percentile compared to the UGI comparator group, the employee will not be paid. At the 40th percentile, the employee will be paid an award equal to 50% of the target award; at the 50th percentile, 100% ; and at the 100th percentile, 200% . The actual amount of the award is interpolated between these percentile rankings. Dividend equivalents are paid in cash only on UGI Performance Units that eventually vest. The fair value of UGI Stock Units on the grant date is equal to the market price of UGI Stock on the grant date plus the fair value of dividend equivalents if applicable. Under GAAP, UGI Performance Units are equity awards with a market-based condition which, if settled in shares, results in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of UGI Performance Units are estimated using a Monte Carlo valuation model. The fair value associated with the target award is accounted for as equity and the fair value of the award over the target, as well as all dividend equivalents, is accounted for as a liability. The expected term of the UGI Performance Unit awards is three years based on the performance period. Expected volatility is based on the historical volatility of UGI Common Stock over a three -year period. The risk-free interest rate is based on the yields on U.S. Treasury bonds at the time of grant. Volatility for all companies in the UGI comparator groups is based on historical volatility. The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs: Grants Awarded in Fiscal Year 2016 2015 2014 Risk free rate 1.3% 1.1% 0.8% Expected life 3 years 3 years 3 years Expected volatility 17.5% 15.9% 20.3% Dividend yield 2.7% 2.3% 2.7% The weighted-average grant date fair value of UGI Performance Unit awards was estimated to be $32.64 for Units granted in Fiscal 2016 , $38.43 for Units granted in Fiscal 2015 and $32.32 for Units granted in Fiscal 2014 . The following table summarizes UGI Unit award activity for Fiscal 2016 : Total Vested Non-Vested Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) September 30, 2015 1,136,251 $ 23.78 803,817 $ 20.19 332,434 $ 32.28 UGI Performance Units: Granted 178,160 $ 32.64 25,291 $ 32.77 152,869 $ 32.62 Forfeited (17,356 ) $ 34.62 — $ — (17,356 ) $ 34.62 Vested — $ — 154,339 $ 28.66 (154,339 ) $ 28.66 Unit awards paid (296,687 ) $ 25.98 (296,687 ) $ 25.98 — $ — UGI Stock Units: Granted (a) 52,493 $ 34.39 39,093 $ 33.40 13,400 $ 37.29 Unit awards paid (53,778 ) $ 16.86 (53,778 ) $ 16.86 — $ — September 30, 2016 999,083 $ 25.44 672,075 $ 21.17 327,008 $ 34.21 (a) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2015 and Fiscal 2014 were 39,801 and 44,814 , respectively. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows: 2016 2015 2014 UGI Performance Unit awards: Number of original awards granted 308,362 294,300 331,038 Fiscal year granted 2013 2012 2011 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 209,592 188,418 174,168 Cash paid $ 13.9 $ 13.3 $ 3.1 UGI Stock Unit awards: Number of original awards granted 51,037 67,419 34,639 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 39,422 44,034 22,604 Cash paid $ 0.7 $ 0.8 $ 0.4 During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , we granted UGI Unit awards representing 230,653 , 180,724 and 234,264 shares, respectively, having weighted-average grant date fair values per Unit of $33.04 , $38.20 and $31.38 , respectively. As of September 30, 2016 , there was a total of approximately $8.6 of unrecognized compensation cost associated with 999,083 UGI Unit awards outstanding that is expected to be recognized over a weighted-average period of 1.8 years . The total fair values of UGI Units that vested during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 were $9.7 , $15.3 and $8.7 , respectively. As of September 30, 2016 and 2015 , total liabilities of $18.5 and $19.9 , respectively, associated with UGI Unit awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets. At September 30, 2016 , 13,042,345 shares of Common Stock were available for future grants under the 2013 OICP, and up to 4,116 shares of Common Stock were available for future grants of stock options under the 2004 OECP. AmeriGas Partners Equity-Based Compensation Plans and Awards. Under the AmeriGas Propane, Inc. 2010 Long-Term Incentive Plan on Behalf of AmeriGas Partners, L.P. (“2010 Propane Plan”), the General Partner may award to employees and non-employee directors grants of AmeriGas Partners Units (comprising “AmeriGas Stock Units” and “AmeriGas Performance Units”), options, phantom units, unit appreciation rights and other Common Unit-based awards. The total aggregate number of Common Units that may be issued under the 2010 Propane Plan is 2,800,000 . The exercise price for options may not be less than the fair market value on the date of grant. Awards granted under the 2010 Propane Plan may vest immediately or ratably over a period of years, and options can be exercised no later than ten years from the grant date. In addition, the 2010 Propane Plan provides that Common Unit-based awards may also provide for the crediting of Common Unit distribution equivalents to participants’ accounts. AmeriGas Stock Unit and AmeriGas Performance Unit awards entitle the grantee to AmeriGas Partners Common Units or cash once the service condition is met and, with respect to AmeriGas Performance Units, subject to market performance conditions, and for certain awards granted on or after January 1, 2015, actual net customer acquisition and retention performance. Recipients of AmeriGas Performance Unit awards are awarded a target number of AmeriGas Performance Units. The number of AmeriGas Performance Units ultimately paid at the end of the performance period (generally three years ) may be higher or lower than the target number, or it may be zero. For that portion of Performance Unit awards whose ultimate payout is based upon market-based conditions (as further described below), the number of awards ultimately paid is based upon AmeriGas Partners’ Total Unitholder Return (“TUR”) percentile rank relative to entities in a master limited partnership peer group (“Alerian MLP Group”) and, for certain AmeriGas Performance Unit awards granted beginning in January 2014, based upon AmeriGas Partners’ TUR relative to the two other publicly traded propane master limited partnerships in the Alerian MLP Group (“Propane MLP Group”). For Performance Unit awards granted on or after January 1, 2015, the number of AmeriGas Performance Units ultimately paid is based upon AmeriGas Partner’s TUR percentile rank relative to entities in the Alerian MLP Group as modified by AmeriGas Partners’ performance relative to the Propane MLP Group. With respect to AmeriGas Performance Unit awards subject to measurement compared with the Alerian MLP Group, grantees may receive from 0 % to 200 % of the target award granted. For such grants issued on or after January 1, 2013, if AmeriGas Partners’ TUR is below the 25th percentile compared to the peer group, the grantee will not be paid. At the 25th percentile, the employee will be paid an award equal to 25 % of the target award; at the 40th percentile, 70 %; at the 50th percentile, 100 %; at the 60th percentile, 125 %; at the 75th percentile, 162.5 %; and at the 90th percentile or above, 200 %. The actual amount of the award is interpolated between these percentile rankings. For such grants issued on or after January 1, 2015, the amount ultimately paid shall be modified based upon AmeriGas Partners’ TUR ranking relative to the Propane MLP Group over the performance period (“MLP Modifier”). Such modification ranges from 70 % to 130 %, but in no event shall the amount ultimately paid, after such modification, exceed 200 % of the target award grant. With respect to AmeriGas Performance Unit awards granted in January 2014 subject to measurement compared with the Propane MLP Group, grantees will receive 150% of the target award if AmeriGas Partners’ TUR exceeds the TUR of all the other members in the Propane MLP Group. Otherwise there will be no payout of such AmeriGas Performance Units. If one of the other two members of the Propane MLP Group ceases to exist as a publicly traded company or declares bankruptcy (“MLP Event”) and depending upon the timing of such MLP Event, the ultimate amount of such AmeriGas Performance Unit awards to be issued pursuant to the January 2014 grant, and the amount of distribution equivalents to be paid, will depend upon AmeriGas Partners’ TUR rank relative to (1) the Alerian MLP Group for the entire performance period; (2) the Alerian MLP Group for the entire performance period and the Propane MLP Group (through the date of the MLP Event); or (3) the Propane MLP Group through the date of the MLP Event. For those performance awards granted on or after January 1, 2015, that are subject to the MLP Modifier, if an MLP Event were to occur during the performance period such MLP Modifier would be based upon AmeriGas Partners’ TUR rank as determined in (1),(2) or (3) above, as appropriate. With respect to AmeriGas Performance Unit awards granted in January 2015 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0 % and 200 % of the target award based upon the annual actual net customer gain and retention performance as adjusted for the net customer gain and retention performance over the three -year performance period. With respect to AmeriGas Performance Unit awards granted in January 2016 whose payout is based upon net customer gain and retention performance, grantees may ultimately receive between 0% and 200% of the target award based upon the actual net customer gain and retention performance over the entire three -year performance period. Any Common Unit distribution equivalents earned are paid in cash. Generally, except in the event of retirement, death or disability, each grant, unless paid, will terminate when the participant ceases to be employed by the General Partner. There are certain change of control and retirement eligibility conditions that, if met, generally result in accelerated vesting or elimination of further service requirements. Under GAAP, AmeriGas Performance Units awards that are subject to market-based conditions are equity awards that, if settled in Common Units, result in the recognition of compensation cost over the requisite employee service period regardless of whether the market-based condition is satisfied. The fair values of AmeriGas Performance Units subject to market-based conditions are estimated using a Monte Carlo valuation model. The fair value associated with the target award, which will be paid in Common Units, is accounted for as equity and the fair value of the award over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. For purposes of valuing AmeriGas Performance Unit awards that are subject to market-based conditions, expected volatility is based on the historical volatility of Common Units over a three -year period. The risk-free interest rate is based on the rates on U.S. Treasury bonds at the time of grant. Volatility for all entities in the peer group is based on historical volatility. The expected term of the AmeriGas Performance Unit awards is three years based on the performance period. AmeriGas Performance Unit awards whose ultimate payout is based upon net customer acquisition and retention performance measures are recorded as expense when it is probable all or a portion of the award will be paid. The fair value associated with the target award is the market price of the Common Units on the date of grant. The fair value of the award over the target, as well as all Common Unit distribution equivalents, which will be paid in cash, is accounted for as a liability. The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs: Grants Awarded in Fiscal Year 2016 2015 2014 Risk-free rate 1.3% 0.9% 0.8% Expected life 3 years 3 years 3 years Expected volatility 20.6% 19.2% 21.1% Dividend yield 10.7% 6.8% 7.5% The General Partner granted awards under the 2010 Propane Plan representing 73,080 , 80,336 and 86,458 Common Units in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively, having weighted-average grant date fair values per Common Unit subject to award of $36.61 , $61.00 and $43.34 , respectively. At September 30, 2016 , 2,348,046 Common Units were available for future award grants under the 2010 Propane Plan. The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2016 : Total Vested Non-Vested Number of AmeriGas Partners Common Units Subject to Award Weighted Average Grant Date Fair Value (per Unit) Number of AmeriGas Partners Common Units Subject to Award Weighted Average Grant Date Fair Value (per Unit) Number of AmeriGas Partners Common Units Subject to Award Weighted Average Grant Date Fair Value (per Unit) September 30, 2015 192,583 $ 49.70 46,900 $ 44.97 145,683 $ 51.22 AmeriGas Performance Units: Granted 52,495 $ 37.65 1,267 $ 37.84 51,228 $ 37.65 Forfeited (4,994 ) $ 54.00 — $ — (4,994 ) $ 54.00 Vested — $ — 30,050 $ 43.65 (30,050 ) $ 43.65 Awards paid (34,616 ) $ 42.44 (34,616 ) $ 42.44 — $ — AmeriGas Stock Units: Granted 20,585 $ 38.65 12,785 $ 36.69 7,800 $ 41.85 Forfeited (800 ) $ 42.33 — $ — (800 ) $ 42.33 Vested — $ — 13,940 $ 49.94 (13,940 ) $ 49.94 Awards paid (14,704 ) $ 49.94 (14,704 ) $ 49.94 — $ — September 30, 2016 210,549 $ 47.24 55,622 $ 45.67 154,927 $ 47.80 During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows: 2016 2015 2014 AmeriGas Performance Unit awards: Number of Common Units subject to original awards granted 44,800 55,750 41,251 Fiscal year granted 2013 2012 2011 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 23,017 — — Cash paid $ 1.7 $ — $ — AmeriGas Stock Unit awards: Number of Common Units subject to original awards granted 20,336 42,532 72,023 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 9,272 21,509 40,842 Cash paid $ 0.4 $ 0.8 $ 1.4 As of September 30, 2016 , there was a total of approximately $1.8 of unrecognized compensation cost associated with 210,549 Common Units subject to award that is expected to be recognized over a weighted-average period of 1.5 years . The total fair values of Common Unit-based awards that vested during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 were $2.0 , $2.6 and $4.1 , respectively. As of September 30, 2016 and 2015 , total liabilities of $3.5 and $3.3 associated with Common Unit-based awards are reflected in employee compensation and benefits accrued and other noncurrent liabilities in the Consolidated Balance Sheets. It is the Partnership’s practice to issue new AmeriGas Partners Common Units for the portion of any Common Unit-based awards paid in AmeriGas Partners Common Units.

Partnership Distributions

Partnership Distributions	12 Months Ended
	Sep. 30, 2016
Distributions Made to Members or Limited Partners [Abstract]
Partnership Distributions	Note 14 — Partnership Distributions The Partnership makes distributions to its partners approximately 45 days after the end of each fiscal quarter in a total amount equal to its Available Cash (as defined in the Partnership Agreement) for such quarter. Available Cash generally means: 1. all cash on hand at the end of such quarter, plus 2. all additional cash on hand as of the date of determination resulting from borrowings after the end of such quarter, less 3. the amount of cash reserves established by the General Partner in its reasonable discretion. The General Partner may establish reserves for the proper conduct of the Partnership’s business and for distributions during the next four quarters. Distributions of Available Cash are made 98% to limited partners and 2% to the General Partner (representing a 1% General Partner interest in AmeriGas Partners and 1.01% interest in AmeriGas OLP) until Available Cash exceeds the Minimum Quarterly Distribution of $0.55 and the First Target Distribution of $0.055 per Common Unit (or a total of $0.605 per Common Unit). When Available Cash exceeds $0.605 per Common Unit in any quarter, the General Partner will receive a greater percentage of the total Partnership distribution (the “incentive distribution”) but only with respect to the amount by which the distribution per Common Unit to limited partners exceeds $0.605 . During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the Partnership made quarterly distributions to Common Unitholders in excess of $0.605 per limited partner unit. As a result, the General Partner has received a greater percentage of the total Partnership distribution than its aggregate 2% general partner interest in AmeriGas OLP and AmeriGas Partners. During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the total amount of distributions received by the General Partner with respect to its aggregate 2% general partner ownership interests totaled $47.4 , $39.3 and $32.4 , respectively. Included in these amounts are incentive distributions received by the General Partner during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 of $38.2 , $30.4 and $23.9 , respectively.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 15 — Commitments and Contingencies Commitments We lease various buildings and other facilities and vehicles, computer and office equipment under operating leases. Certain of our leases contain renewal and purchase options and also contain step-rent provisions. Our aggregate rental expense for such leases was $102.0 in Fiscal 2016 , $86.1 in Fiscal 2015 and $79.7 in Fiscal 2014 . Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows: 2017 2018 2019 2020 2021 After 2021 AmeriGas Propane $ 60.6 $ 53.2 $ 48.4 $ 44.3 $ 37.0 $ 103.8 UGI Utilities 6.0 5.0 3.0 1.3 0.6 0.2 UGI International 11.4 8.8 6.4 4.2 2.8 8.0 Other 2.1 2.0 1.7 1.5 0.3 0.1 Total $ 80.1 $ 69.0 $ 59.5 $ 51.3 $ 40.7 $ 112.1 Our businesses enter into contracts of varying lengths and terms to meet their supply, pipeline transportation, storage, capacity and energy needs. Gas Utility currently has gas supply agreements with producers and marketers with terms not exceeding 16 months. Gas Utility also has agreements for firm pipeline transportation and natural gas storage services, which Gas Utility may terminate at various dates through Fiscal 2030 . Gas Utility’s costs associated with transportation and storage capacity agreements are included in its annual PGC filings with the PUC and are recoverable through PGC rates. In addition, Gas Utility has short-term gas supply agreements which permit it to purchase certain of its gas supply needs on a firm or interruptible basis at spot-market prices. Electric Utility purchases its electricity needs under contracts with various suppliers and on the spot market. Contracts with producers for energy needs expire at various dates through Fiscal 2017 . Midstream & Marketing enters into fixed-price contracts with suppliers to purchase natural gas and electricity to meet its sales commitments. Generally, these contracts have terms of less than two years. The Partnership enters into fixed-price and variable-price contracts to purchase a portion of its supply requirements. These contracts currently have terms that do not exceed three years. UGI International enters into fixed-price and variable-priced contracts to purchase a portion of its supply requirements that currently do not exceed three years. The following table presents contractual obligations under UGI Utilities, Midstream & Marketing and UGI International supply, storage and service contracts existing at September 30, 2016 : 2017 2018 2019 2020 2021 After 2021 UGI Utilities supply, storage and transportation contracts $ 115.1 $ 71.1 $ 50.8 $ 36.5 $ 35.0 $ 116.0 Midstream & Marketing supply contracts 168.4 80.4 34.0 2.3 — — UGI International supply contracts 78.7 — — — — — Total $ 362.2 $ 151.5 $ 84.8 $ 38.8 $ 35.0 $ 116.0 The Partnership and UGI International also enter into other contracts to purchase LPG to meet supply requirements. Generally, these contracts are one - to three -year agreements subject to annual price and quantity adjustments. Contingencies Environmental Matters UGI Utilities From the late 1800s through the mid-1900s, UGI Utilities and its current and former subsidiaries owned and operated a number of manufactured gas plants (“MGPs”) prior to the general availability of natural gas. Some constituents of coal tars and other residues of the manufactured gas process are today considered hazardous substances under the Superfund Law and may be present on the sites of former MGPs. Between 1882 and 1953, UGI Utilities owned the stock of subsidiary gas companies in Pennsylvania and elsewhere and also operated the businesses of some gas companies under agreement. By the early 1950s, UGI Utilities divested all of its utility operations other than certain Pennsylvania operations, including those which now constitute UGI Gas and Electric Utility. UGI Utilities also has two acquired subsidiaries (CPG and PNG) which have similar histories of owning, and in some cases operating, MGPs in Pennsylvania. UGI Utilities and its subsidiaries have entered into agreements with the Pennsylvania Department of Environmental Protection (“DEP”) to address the remediation of former MGPs in Pennsylvania. CPG is party to a Consent Order and Agreement (“CPG-COA”) with the DEP requiring CPG to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“CPG MGP Properties”) and to plug a minimum number of non-producing natural gas wells per year. In addition, PNG is a party to a Multi-Site Remediation Consent Order and Agreement (“PNG-COA”) with the DEP. The PNG-COA requires PNG to perform annually a specified level of activities associated with environmental investigation and remediation work at certain properties on which MGP-related facilities were operated (“PNG MGP Properties”). Under these agreements, required environmental expenditures relating to the CPG MGP Properties and the PNG MGP Properties are capped at $1.8 and $1.1 , respectively, in any calendar year. The CPG-COA is scheduled to terminate at the end of 2018. The PNG-COA terminates in 2019 but may be terminated by either party effective at the end of any two -year period beginning with the original effective date in March 2004. At September 30, 2016 and 2015 , our accrued liabilities for estimated environmental investigation and remediation costs related to the CPG-COA and the PNG-COA totaled $11.3 and $13.8 , respectively. CPG and PNG have recorded associated regulatory assets for these costs because recovery of these costs from customers is probable (see Note 8 ). In May 2016, UGI Gas executed a Consent Order and Agreement (“UGI Gas-COA”) with the DEP with an effective date of October 1, 2016. The UGI Gas-COA will terminate in September 2031 if not extended by the parties. The UGI Gas-COA requires UGI Gas to perform a specified level of activities associated with environmental investigation and remediation work at certain properties in Pennsylvania on which MGP related facilities were operated (“UGI Gas MGP Properties”). Under this agreement, required environmental expenditures related to the UGI Gas MGP Properties are capped at $2.5 in any calendar year. At September 30, 2016 , our estimated accrued liabilities for environmental investigation and remediation costs related to the UGI Gas-COA totaled $43.7 . UGI Gas has recorded an associated regulatory asset for these costs because recovery of these costs from customers is probable (see Note 8 ). We do not expect the costs for investigation and remediation of hazardous substances at Pennsylvania MGP sites to be material to UGI Utilities’ results of operations because UGI Gas, CPG and PNG receive ratemaking recognition of estimated environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. From time to time, UGI Utilities is notified of sites outside Pennsylvania on which private parties allege MGPs were formerly owned or operated by UGI Utilities or owned or operated by its former subsidiaries. Such parties generally investigate the extent of environmental contamination or perform environmental remediation. Management believes that under applicable law UGI Utilities should not be liable in those instances in which a former subsidiary owned or operated an MGP. There could be, however, significant future costs of an uncertain amount associated with environmental damage caused by MGPs outside Pennsylvania that UGI Utilities directly operated, or that were owned or operated by former subsidiaries of UGI Utilities if a court were to conclude that (1) the subsidiary’s separate corporate form should be disregarded, or (2) UGI Utilities should be considered to have been an operator because of its conduct with respect to its subsidiary’s MGP. At September 30, 2016 , neither the undiscounted nor the accrued liability for environmental investigation and cleanup costs for UGI Utilities MGP sites outside of Pennsylvania was material. Other Matters Purported Class Action Lawsuits. In connection with the Partnership’s 2012 acquisition of the subsidiaries of Energy Transfer Partners, L.P. (“ETP”) that operated ETP’s propane distribution business (“Heritage Propane”), the Partnership became party to a class action lawsuit that was filed against Heritage Operating, L.P. in 2005 by Alfred L. Williams, II, on behalf of himself and all others similarly situated. The class action lawsuit alleged, among other things, wrongful collection of tank rental payments from legacy customers of People’s Gas, which was acquired by Heritage Propane in 2000. In 2010, the Florida District Court certified the class and in January 2015, the Florida District Court awarded the class approximately $18 . In April 2016, the Partnership appealed the verdict to the Florida Second District Court of Appeals (the “Second DCA”) and, in September 2016, the Second DCA affirmed the verdict without opinion. Prior to the Second DCA’s action in the case, we believed that the likelihood of the Second DCA affirming the Florida District Court’s decision was remote. As a result of the Second DCA’s actions, in September 2016, the Partnership recorded a $15.0 adjustment to its litigation accrual to reflect the full amount of the award plus associated interest. In October 2016, the Partnership filed a Motion for Written Opinion and for Rehearing En Banc with the Second DCA, which motions are still pending. We believe we have strong arguments to support the aforementioned motions. Between May and October of 2014, more than 35 purported class action lawsuits were filed in multiple jurisdictions against the Partnership/UGI Corporation and a competitor by certain of their direct and indirect customers. The class action lawsuits allege, among other things, that the Partnership and its competitor colluded, beginning in 2008, to reduce the fill level of portable propane cylinders from 17 pounds to 15 pounds and combined to persuade their common customer, Walmart Stores, Inc., to accept that fill reduction, resulting in increased cylinder costs to retailers and end-user customers in violation of federal and certain state antitrust laws. The claims seek treble damages, injunctive relief, attorneys’ fees and costs on behalf of the putative classes. On October 16, 2014, the United States Judicial Panel on Multidistrict Litigation transferred all of these purported class action cases to the Western Division of the United States District Court for the Western District of Missouri (“District Court”). In July 2015, the District Court dismissed all claims brought by direct customers and all claims other than those for injunctive relief brought by indirect customers. The direct customers filed an appeal with the United States Court of Appeals for the Eighth Circuit (“Eighth Circuit”) and in August 2016, the Eighth Circuit affirmed the District Court’s dismissal of the direct customer’s claims against the Partnership/UGI Corporation. The direct customers filed a petition requesting an en banc review of the Eighth Circuit decision, which is still pending. The indirect customers filed an amended complaint claiming injunctive relief and state law claims under Wisconsin, Maine and Vermont law. In September 2016, the District Court dismissed the amended complaint in its entirety. The indirect purchasers appealed this decision to the Eighth Circuit, and the appeal is still pending. On July 21, 2016, several new indirect purchaser plaintiffs filed an antitrust class action lawsuit against the Partnership in the Western District of Missouri. The new indirect purchaser class action lawsuit was dismissed in September 2016 and certain indirect purchaser plaintiffs appealed this decision, consolidating their appeal with the indirect purchaser appeal that is pending in the Eighth Circuit. We are unable to reasonably estimate the impact, if any, arising from such litigation. We believe we have strong defenses to the claims and intend to vigorously defend against them. In addition to the matters described above, there are other pending claims and legal actions arising in the normal course of our businesses. Although we cannot predict the final results of these pending claims and legal actions, we believe, after consultation with counsel, that the final outcome of these matters will not have a material effect on our financial position, results of operations or cash flows.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 16 — Fair Value Measurements Recurring Fair Value Measurements The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 , as of September 30, 2016 and 2015 : Asset (Liability) Level 1 Level 2 Level 3 Total September 30, 2016: Derivative instruments: Assets: Commodity contracts $ 28.9 $ 26.0 $ — $ 54.9 Foreign currency contracts $ — $ 17.8 $ — $ 17.8 Liabilities: Commodity contracts $ (76.8 ) $ (21.8 ) $ — $ (98.6 ) Foreign currency contracts $ — $ (2.4 ) $ — $ (2.4 ) Cross-currency swaps $ — $ (0.5 ) $ — $ (0.5 ) Interest rate contracts $ — $ (3.9 ) $ — $ (3.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 33.0 $ — $ — $ 33.0 September 30, 2015 Derivative instruments: Assets: Commodity contracts $ 17.4 $ 11.6 $ — $ 29.0 Foreign currency contracts $ — $ 29.1 $ — $ 29.1 Cross-currency swaps $ — $ 0.4 $ — $ 0.4 Liabilities: Commodity contracts $ (70.0 ) $ (99.0 ) $ — $ (169.0 ) Foreign currency contracts $ — $ (0.1 ) $ — $ (0.1 ) Interest rate contracts $ — $ (10.8 ) $ — $ (10.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 30.3 $ — $ — $ 30.3 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 7 ). The fair values of our Level 1 exchange-traded commodity futures and option contracts and non-exchange-traded commodity futures and forward contracts are based upon actively quoted market prices for identical assets and liabilities. The remainder of our derivative instruments are designated as Level 2. The fair values of certain non-exchange traded commodity derivatives designated as Level 2 are based upon indicative price quotations available through brokers, industry price publications or recent market transactions and related market indicators. For commodity option contracts designated as Level 2 that are not traded on an exchange, we use a Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The fair values of our Level 2 interest rate contracts, foreign currency contracts and cross-currency contracts are based upon third-party quotes or indicative values based on recent market transactions. The fair values of investments held in grantor trusts are derived from quoted market prices as substantially all of the investments in these trusts have active markets. There were no transfers between Level 1 and Level 2 during the periods presented. Other Financial Instruments The carrying amounts of other financial instruments included in current assets and current liabilities (except for current maturities of long-term debt) approximate their fair values because of their short-term nature. At September 30, 2016 , the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) were $3,832.3 and $4,052.3 , respectively. At September 30, 2015 , the carrying amount and estimated fair value of our long-term debt (including current maturities but excluding unamortized debt issuance costs) were $3,699.8 and $3,803.1 , respectively. We estimate the fair value of long-term debt by using current market rates and by discounting future cash flows using rates available for similar type debt (Level 2). Financial instruments other than derivative instruments, such as short-term investments and trade accounts receivable, could expose us to concentrations of credit risk. We limit credit risk from short-term investments by investing only in investment-grade commercial paper, money market mutual funds, securities guaranteed by the U.S. Government or its agencies and FDIC insured bank deposits. The credit risk arising from concentrations of trade accounts receivable is limited because we have a large customer base that extends across many different U.S. markets and a number of foreign countries. For information regarding concentrations of credit risk associated with our derivative instruments, see Note 17 . Our investment in a private equity partnership is measured at fair value on a non-recurring basis. Generally this measurement uses Level 3 fair value inputs because the investment does not have a readily available market value.

Derivative Instruments and Hedg

Derivative Instruments and Hedging Activities	12 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities	Note 17 — Derivative Instruments and Hedging Activities We are exposed to certain market risks associated with our business operations. Management uses derivative financial and commodity instruments, among other things, to manage these risks. The primary risks managed by derivative instruments are (1) commodity price risk, (2) interest rate risk, and (3) foreign currency exchange rate risk. Although we use derivative financial and commodity instruments to reduce market risk associated with forecasted transactions, we do not use derivative financial and commodity instruments for speculative or trading purposes. The use of derivative instruments is controlled by our risk management and credit policies, which govern, among other things, the derivative instruments we can use, counterparty credit limits and contract authorization limits. Although some of our commodity derivative instruments extend over a number of years, a significant portion of our commodity derivative instruments economically hedge commodity price risk during the next twelve months. For information on the accounting for our derivative instruments, see Note 2 . Commodity Price Risk Regulated Utility Operations Natural Gas Gas Utility’s tariffs contain clauses that permit recovery of all of the prudently incurred costs of natural gas it sells to retail core-market customers, including the cost of financial instruments used to hedge purchased gas costs. As permitted and agreed to by the PUC pursuant to Gas Utility’s annual PGC filings, Gas Utility currently uses New York Mercantile Exchange (“NYMEX”) natural gas futures and option contracts to reduce commodity price volatility associated with a portion of the natural gas it purchases for its retail core-market customers. Gains and losses on Gas Utility’s natural gas futures contracts and natural gas option contracts are recorded in regulatory assets or liabilities on the Consolidated Balance Sheets because it is probable such gains or losses will be recoverable from, or refundable to, customers through the PGC recovery mechanism (see Note 8 ). Electricity Electric Utility’s DS tariffs permit the recovery of all prudently incurred costs of electricity it sells to DS customers, including the cost of financial instruments used to hedge electricity costs. Electric Utility enters into forward electricity purchase contracts to meet a substantial portion of its electricity supply needs. At September 30, 2016 and 2015 , substantially all of such contracts qualified for the NPNS exception under GAAP. In order to reduce volatility associated with a substantial portion of its electricity transmission congestion costs, Electric Utility obtains FTRs through an annual allocation process. Gains and losses on Electric Utility FTRs are recorded in regulatory assets or liabilities in accordance with GAAP because it is probable such gains or losses will be recoverable from, or refundable to, customers through the DS mechanism (see Note 8 ). Non-utility Operations LPG In order to manage market price risk associated with the Partnership’s fixed-price programs, the Partnership uses over-the-counter derivative commodity instruments, principally price swap contracts. In addition, the Partnership, certain other domestic business units and our UGI International operations also use over-the-counter price swap and option contracts to reduce commodity price volatility associated with a portion of their forecasted LPG purchases. The Partnership from time to time enters into price swap and put option agreements to reduce the effects of short-term commodity price volatility. Natural Gas In order to manage market price risk relating to fixed-price sales contracts for natural gas, Midstream & Marketing enters into NYMEX and over-the-counter natural gas futures and forward contracts and Intercontinental Exchange (“ICE”) natural gas basis swap contracts. In addition, Midstream & Marketing uses NYMEX futures contracts to economically hedge the gross margin associated with the purchase and anticipated later near-term sale of natural gas or propane. Because it could no longer assert the NPNS exception under GAAP for new contracts entered into for the forward purchase of natural gas and pipeline transportation, beginning in the second quarter of Fiscal 2014 Energy Services began recording these contracts at fair value with changes in fair value reflected in cost of sales. Electricity In order to manage market price risk relating to fixed-price sales contracts for electricity, Midstream & Marketing enters into electricity futures and forward contracts. Midstream & Marketing also uses NYMEX and over-the-counter electricity futures contracts to economically hedge the price of a portion of its anticipated future sales of electricity from its electric generation facilities. From time to time, Midstream & Marketing purchases FTRs to economically hedge electricity transmission congestion costs associated with its fixed-price electricity sales contracts and also enters into New York Independent System Operator (“NYISO”) capacity swap contracts to economically hedge the locational basis differences for customers it serves on the NYISO electricity grid. Interest Rate Risk France SAS’ and Flaga’s long-term debt agreements have interest rates that are generally indexed to short-term market interest rates. France SAS and Flaga have each entered into pay-fixed, receive-variable interest rate swap agreements to hedge the underlying euribor rates of interest on their variable-rate term loans. The France SAS swaps were originally executed in Fiscal 2015, at which time such swaps were designated in a cash flow hedging relationship associated with €600 notional amount of term loan debt issued in conjunction with the Totalgaz Acquisition. In March 2016, France SAS amended the terms of its pay-fixed, receive-variable interest rate swap agreements associated with the €600 term loan debt to purchase a 0% floor that is identical to the 0% floor embedded in France SAS’ term loan debt. In conjunction with the amendments, in March 2016 France SAS paid its interest rate swap counterparties €7.7 , which amount substantially equaled the interest rate swaps’ fair value. Concurrent with the amendments to the interest rate swaps, the swaps were simultaneously de-designated and re-designated as cash flow hedges of future anticipated interest payments associated with the €600 term loan debt. The amended swaps fix the underlying euribor rate on the €600 term loan at 0.18% . Our domestic businesses’ long-term debt is typically issued at fixed rates of interest. As these long-term debt issues mature, we typically refinance such debt with new debt having interest rates reflecting then-current market conditions. In order to reduce market rate risk on the underlying benchmark rate of interest associated with near- to medium-term forecasted issuances of fixed-rate debt, from time to time we enter into interest rate protection agreements (“IRPAs”). On March 31, 2016, concurrent with the pricing of UGI Utilities’ Senior Notes to be issued under the 2016 Note Purchase Agreement, UGI Utilities settled all of its then-existing IRPA contracts associated with such debt at a loss of $36.0 . Because these IRPA contracts qualified for and were designated as cash flow hedges, the loss recognized in connection with the settled IRPAs was recorded in AOCI and will be recognized in interest expense as the associated future interest expense impacts earnings. See Note 5 for additional information on UGI Utilities 2016 Note Purchase Agreement. We account for interest rate swaps and IRPAs as cash flow hedges. At September 30, 2016 , the amount of net losses associated with interest rate hedges (excluding pay-fixed, receive-variable interest rate swaps) expected to be reclassified into earnings during the next twelve months is $3.4 . Foreign Currency Exchange Rate Risk Forward foreign currency exchange contracts In order to reduce exposure to foreign exchange rate volatility related to certain of our foreign LPG operations, we hedge a portion of their anticipated U.S. dollar-denominated LPG product purchases primarily during the heating-season months of October thru March through the use of forward foreign currency exchange contracts. From time to time we also enter into forward foreign currency exchange contracts to reduce the volatility of the U.S. dollar value of a portion of our International Propane euro-denominated net investments. We account for foreign currency exchange contracts associated with anticipated purchases of U.S. dollar-denominated LPG as cash flow hedges. At September 30, 2016 , the amount of net gains associated with currency rate risk expected to be reclassified into earnings during the next twelve months based upon current fair values is $11.5 . Cross-Currency Swaps From time to time, Flaga enters into cross-currency swaps to hedge its exposure to the variability in expected future cash flows associated with the foreign currency and interest rate risk of U.S. dollar-denominated debt. These cross-currency hedges include initial and final exchanges of principal from a fixed euro denomination to a fixed U.S. dollar-denominated amount, to be exchanged at a specified rate, which was determined by the market spot rate on the date of issuance. These cross-currency swaps also include interest rate swaps of a fixed foreign-denominated interest rate to a fixed U.S. dollar-denominated interest rate. We designate these cross-currency swaps as cash flow hedges. At September 30, 2016 , the amount of net losses associated with this cross-currency swap expected to be reclassified into earnings during the next twelve months is not material. Quantitative Disclosures Related to Derivative Instruments The following table summarizes the gross notional amounts related to open derivative contracts at September 30, 2016 and 2015 and the final settlement date of the Company's open derivative transactions broken out by derivative type as of September 30, 2016 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through 2016 2015 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2017 18.4 18.9 Electric Utility forward electricity purchase contracts Kilowatt hours N/A — 136.0 FTRs & NYISO capacity contracts Kilowatt hours May 2017 58.3 277.1 Non-utility operations LPG swaps & options Gallons September 2019 396.9 516.3 Natural gas futures, forward and pipeline contracts Dekatherms December 2020 71.1 110.2 Natural gas basis swap contracts Dekatherms December 2020 118.3 75.7 NYMEX natural gas storage Dekatherms March 2017 1.9 1.9 NYMEX propane storage Gallons N/A — 2.0 Electricity long forward and futures contracts Kilowatt hours January 2020 761.2 474.3 Electricity short forward and futures contracts Kilowatt hours January 2020 264.6 297.9 FTRs & NYISO capacity contracts Kilowatt hours N/A — 82.0 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 IRPAs USD N/A $ — $ 250.0 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2019 $ 314.3 $ 227.9 Cross-currency swaps USD September 2018 $ 59.1 $ 59.1 Derivative Instrument Credit Risk We are exposed to risk of loss in the event of nonperformance by our derivative instrument counterparties. Our derivative instrument counterparties principally comprise large energy companies and major U.S. and international financial institutions. We maintain credit policies with regard to our counterparties that we believe reduce overall credit risk. These policies include evaluating and monitoring our counterparties’ financial condition, including their credit ratings, and entering into agreements with counterparties that govern credit limits or entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. Certain of these agreements call for the posting of collateral by the counterparty or by the Company in the forms of letters of credit, parental guarantees or cash. Additionally, our commodity exchange-traded futures contracts generally require cash deposits in margin accounts. At September 30, 2016 and 2015 , restricted cash in brokerage accounts totaled $15.6 and $54.9 , respectively. Although we have concentrations of credit risk associated with derivative instruments, the maximum amount of loss, based upon the gross fair values of the derivative instruments, we would incur if these counterparties failed to perform according to the terms of their contracts was not material at September 30, 2016 . Certain of the Partnership’s derivative contracts have credit-risk-related contingent features that may require the posting of additional collateral in the event of a downgrade of the Partnership’s debt rating. At September 30, 2016 , if the credit-risk-related contingent features were triggered, the amount of collateral required to be posted would not be material. Offsetting Derivative Assets and Liabilities Derivative assets and liabilities (and cash collateral received and pledged) are presented net by counterparty on the Consolidated Balance Sheets if the right of offset exists. Our derivative instruments include both those that are executed on an exchange through brokers and centrally cleared and over-the-counter transactions. Exchange contracts utilize a financial intermediary, exchange, or clearinghouse to enter, execute, or clear the transactions. Over-the-counter contracts are bilateral contracts that are transacted directly with a third party. Certain over-the-counter and exchange contracts contain contractual rights of offset through master netting arrangements, derivative clearing agreements, and contract default provisions. In addition, the contracts are subject to conditional rights of offset through counterparty nonperformance, insolvency or other conditions. In general, most of our over-the-counter transactions and all exchange contracts are subject to collateral requirements. Types of collateral generally include cash or letters of credit. Cash collateral paid by us to our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative liabilities. Cash collateral received by us from our over-the-counter derivative counterparties, if any, is reflected in the table below to offset derivative assets. Certain other accounts receivable and accounts payable balances recognized on the Consolidated Balance Sheets with our derivative counterparties are not included in the table below but could reduce our net exposure to such counterparties because such balances are subject to master netting or similar arrangements. Fair Value of Derivative Instruments The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2016 and 2015 : 2016 2015 Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 17.8 $ 29.1 Cross-currency contracts — 0.4 17.8 29.5 Derivatives subject to PGC and DS mechanisms: Commodity contracts 4.5 1.3 Derivatives not designated as hedging instruments: Commodity contracts 50.4 27.7 Total derivative assets - gross 72.7 58.5 Gross amounts offset in the balance sheet (35.0 ) (18.9 ) Cash collateral received (0.3 ) — Total derivative assets - net $ 37.4 $ 39.6 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ (2.4 ) $ (0.1 ) Cross-currency contracts (0.5 ) — Interest rate contracts (3.9 ) (10.8 ) (6.8 ) (10.9 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.5 ) (5.6 ) Derivatives not designated as hedging instruments: Commodity contracts (98.1 ) (163.4 ) Total derivative liabilities - gross (105.4 ) (179.9 ) Gross amounts offset in the balance sheet 35.0 18.9 Cash collateral pledged — 8.0 Total derivative liabilities - net $ (70.4 ) $ (153.0 ) Effect of Derivative Instruments The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 : Gain or (Loss) Recognized in AOCI and Noncontrolling Interests Gain or (Loss) Reclassified from AOCI and Noncontrolling Interests into Income Location of Gain or (Loss) Reclassified from Interests into Income 2016 2015 2014 2016 2015 2014 Cash Flow Hedges: Commodity contracts $ — $ — $ 50.8 $ — $ (2.2 ) $ 67.0 Cost of sales Foreign currency contracts 3.6 26.0 15.3 17.2 9.7 (3.7 ) Cost of sales Cross-currency contracts 0.1 5.4 3.1 0.4 8.5 (0.1 ) Interest expense Interest rate contracts (32.5 ) (6.6 ) (3.1 ) (4.5 ) (20.4 ) (15.9 ) Interest expense /other operating income, net Total $ (28.8 ) $ 24.8 $ 66.1 $ 13.1 $ (4.4 ) $ 47.3 Gain or (Loss) Recognized in Income Location of Recognized in Income 2016 2015 2014 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ (65.0 ) $ (375.8 ) $ (36.3 ) Cost of sales Commodity contracts (2.2 ) 0.3 — Revenues Commodity contracts (0.1 ) (0.8 ) — Operating and administrative expenses / other operating income, net Total $ (67.3 ) $ (376.3 ) $ (36.3 ) For Fiscal 2016 , the amounts of derivative gains or losses representing ineffectiveness were losses of $5.5 , which are recorded in other operating income, net, on the Consolidated Statements of Income and are related to interest rate contracts at UGI France. The amounts of derivative gains or losses representing ineffectiveness, and the amounts of gains or losses recognized in income as a result of excluding derivatives from ineffectiveness testing, were not material for Fiscal 2015 and Fiscal 2014 . In May 2015, the Company prepaid term loans outstanding under Antargaz’ 2011 Senior Facilities Agreement. In conjunction with the prepayment, the Company also settled its associated pay-fixed, receive-variable interest rate swaps, and discontinued cash flow hedge accounting treatment for such swaps. During Fiscal 2015, the Company recorded a pre-tax loss of $9.0 associated with the discontinuance of cash flow hedge accounting for the swaps, which amount is included in interest expense on the Consolidated Statements of Income (see Note 5 ). We are also a party to a number of other contracts that have elements of a derivative instrument. These contracts include, among others, binding purchase orders, contracts that provide for the purchase and delivery, or sale, of energy products, and service contracts that require the counterparty to provide commodity storage, transportation or capacity service to meet our normal sales commitments. Although certain of these contracts have the requisite elements of a derivative instrument, these contracts qualify for NPNS exception accounting under GAAP because they provide for the delivery of products or services in quantities that are expected to be used in the normal course of operating our business and the price in the contract is based on an underlying that is directly associated with the price of the product or service being purchased or sold.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Accumulated Other Comprehensive Income	Note 18 — Accumulated Other Comprehensive Income Other comprehensive income (loss) principally comprises (1) gains and losses on derivative instruments qualifying as cash flow hedges, net of reclassifications to net income; (2) actuarial gains and losses on postretirement benefit plans, net of associated amortization; and (3) foreign currency translation and long-term intra-company transaction adjustments. Changes in AOCI during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 are as follows: Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2013 $ (16.4 ) $ (26.9 ) $ 51.7 $ 8.4 Other comprehensive (loss) income before reclassification adjustments (after-tax) (5.2 ) 54.0 (43.0 ) 5.8 Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 1.6 (47.2 ) — (45.6 ) Reclassification adjustments tax (expense) benefit (0.6 ) 2.0 — 1.4 Reclassification adjustments (after-tax) 1.0 (45.2 ) — (44.2 ) Other comprehensive (loss) income (4.2 ) 8.8 (43.0 ) (38.4 ) Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 8.8 — 8.8 Other comprehensive (loss) income attributable to UGI (4.2 ) 17.6 (43.0 ) (29.6 ) AOCI - September 30, 2014 $ (20.6 ) $ (9.3 ) $ 8.7 $ (21.2 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) (1.2 ) 16.8 (114.1 ) (98.5 ) Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 2.2 4.4 — 6.6 Reclassification adjustments tax expense (0.8 ) (2.8 ) — (3.6 ) Reclassification adjustments (after-tax) 1.4 1.6 — 3.0 Other comprehensive income (loss) 0.2 18.4 (114.1 ) (95.5 ) Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 2.1 — 2.1 Other comprehensive income (loss) attributable to UGI 0.2 20.5 (114.1 ) (93.4 ) AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive loss before reclassification adjustments (after-tax) (10.9 ) (16.5 ) (6.8 ) (34.2 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 2.6 (13.1 ) — (10.5 ) Reclassification adjustments tax (expense) benefit (0.4 ) 5.0 — 4.6 Reclassification adjustments (after-tax) 2.2 (8.1 ) — (5.9 ) Other comprehensive loss attributable to UGI (8.7 ) (24.6 ) (6.8 ) (40.1 ) AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 ) For additional information on amounts reclassified from AOCI relating to derivative instruments, see Note 17 .

Other Operating Income, Net

Other Operating Income, Net	12 Months Ended
	Sep. 30, 2016
Component of Operating Income [Abstract]
Other Operating Income, Net	Note 19 — Other Operating Income, Net Other operating income, net, comprises the following: 2016 2015 2014 Interest and interest-related income $ 0.2 $ 0.8 $ 3.6 Utility non-tariff service income 2.6 4.8 2.7 Finance charges 15.2 12.7 17.5 Gains on sales of fixed assets, net 3.3 11.1 5.4 Other, net 1.1 15.0 6.9 Total other operating income, net $ 22.4 $ 44.4 $ 36.1

Quarterly Data (unaudited)

Quarterly Data (unaudited)	12 Months Ended
	Sep. 30, 2016
Quarterly Financial Data [Abstract]
Quarterly Data (unaudited)	Note 20 — Quarterly Data (unaudited) The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses and also reflect unrealized gains and losses on commodity derivative instruments used to economically hedge commodity price risk (see Note 17). December 31, March 31, June 30, September 30, 2015 2014 2016 2015 2016 (a) 2015 (b) 2016 (a) 2015 Revenues $ 1,606.6 $ 2,004.6 $ 1,972.1 $ 2,455.6 $ 1,130.8 $ 1,148.1 $ 976.2 $ 1,082.8 Operating income (loss) $ 305.5 $ 83.3 $ 615.4 $ 702.1 $ 155.7 $ 56.1 $ (88.6 ) $ (6.6 ) Loss from equity investees $ (0.1 ) $ (1.0 ) $ — $ (0.1 ) $ — $ — $ (0.1 ) $ (0.1 ) Loss on extinguishments of debt $ — $ — $ — $ — $ (37.1 ) $ — $ (11.8 ) $ — Net income (loss) including noncontrolling interests $ 167.9 $ 0.2 $ 408.0 $ 482.2 $ 28.6 $ (15.9 ) $ (115.7 ) $ (52.5 ) Net income (loss) attributable to UGI Corporation $ 114.6 $ 34.1 $ 233.2 $ 246.5 $ 60.7 $ 9.6 $ (43.8 ) $ (9.2 ) Earnings (loss) per common share attributable to UGI Corporation stockholders: Basic $ 0.66 $ 0.20 $ 1.35 $ 1.42 $ 0.35 $ 0.06 $ (0.25 ) $ (0.05 ) Diluted $ 0.65 $ 0.19 $ 1.33 $ 1.40 $ 0.34 $ 0.05 $ (0.25 ) $ (0.05 ) (a) Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5). (b) Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5 ).

Segment Information

Segment Information	12 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Information	Note 21 — Segment Information Our operations comprise six reportable segments generally based upon products or services sold, geographic location and regulatory environment. As more fully described below, effective October 1, 2015, the composition of our UGI Utilities (formerly Gas Utility) and Energy Services reportable segments changed to include certain operating segments previously reflected in Corporate & Other. Our reportable segments comprise: (1) AmeriGas Propane; (2) an international LPG segment comprising UGI France; (3) an international LPG segment principally comprising Flaga and AvantiGas; (4) UGI Utilities; (5) Energy Services; and (6) Electric Generation. We refer to both international segments together as “UGI International” and Energy Services and Electric Generation together as “Midstream & Marketing.” AmeriGas Propane derives its revenues principally from the sale of propane and related equipment and supplies to retail customers in all 50 states. UGI France derives its revenues principally from the distribution of LPG to retail customers in France and, to a lesser extent, Belgium, the Netherlands and Luxembourg, and also from the marketing of natural gas in France and Belgium. Flaga & Other derives its revenues principally from the distribution of LPG to customers in northern, central and eastern Europe and the United Kingdom. UGI Utilities derives its revenues principally from the sale and distribution of natural gas to customers in eastern, northeastern and central Pennsylvania and, to a lesser extent, from the sale and distribution of electricity in two northeastern Pennsylvania counties. Energy Services derives its revenues principally from the sale of natural gas and, to a lesser extent, electricity, LPG and fuel oil as well as revenues and fees from storage, pipeline transportation and natural gas production activities primarily in the Mid-Atlantic and Northeast regions of the U.S. Energy Services also derives its revenues from contracting services provided by HVAC to customers located primarily in the Mid-Atlantic region of the U.S. Electric Generation derives its revenues principally from the sale of electricity through PJM, a regional electricity transmission organization in the eastern U.S. As a result of changes in the composition of information reported to our chief operating decision maker (“CODM”) associated with our regulated utility operations, effective October 1, 2015, we began including our Electric Utility operating segment with our Gas Utility operating segment which we collectively refer to as “UGI Utilities.” Also, as a result of changes in segment management and reporting for HVAC, effective October 1, 2015, we began including our HVAC operating segment with our Energy Services operating segment. Previously, Electric Utility and HVAC, neither of which met the quantitative thresholds for presentation as a reportable segment under GAAP, were reflected in “Corporate & Other” in our segment information. In accordance with GAAP, prior-year amounts have been restated to reflect these changes. The accounting policies of our reportable segments are the same as those described in Note 2 . We evaluate AmeriGas Propane’s performance principally based upon the Partnership’s earnings before interest expense, income taxes, depreciation and amortization as adjusted for the effects of gains and losses on commodity derivative instruments not associated with current-period transactions and other gains and losses that competitors do not necessarily have (“Partnership Adjusted EBITDA”). Although we use Partnership Adjusted EBITDA to evaluate AmeriGas Propane’s profitability, it should not be considered as an alternative to net income (as an indicator of operating performance) or as an alternative to cash flow (as a measure of liquidity or ability to service debt obligations) and is not a measure of performance or financial condition under GAAP. Our definition of Partnership Adjusted EBITDA may be different from that used by other companies. We evaluate the performance of our other reportable segments principally based upon their income before income taxes as adjusted for gains and losses on commodity derivative instruments not associated with current-period transactions. Net gains and losses on commodity derivative instruments not associated with current-period transactions are reflected in Corporate & Other because the Company’s CODM does not consider such items when evaluating the financial performance of our operating segments. No single customer represents more than ten percent of our consolidated revenues. In addition, all of our reportable segments’ revenues, other than those of UGI International, are derived from sources within the United States, and all of our reportable segments’ long-lived assets, other than those of UGI International, are located in the United States. Midstream & Marketing UGI International Total Elim- inations AmeriGas Propane UGI Utilities Energy Services Electric Generation UGI France Flaga & Other Corporate & Other (b) 2016 Revenues $ 5,685.7 $ (143.9 ) (c) $ 2,311.8 $ 768.5 $ 813.8 $ 62.8 $ 1,344.7 $ 524.1 $ 3.9 Cost of sales $ 2,437.5 $ (141.5 ) (c) $ 864.8 $ 289.8 $ 583.7 $ 28.5 $ 597.6 $ 306.2 $ (91.6 ) Operating income $ 988.0 $ 0.2 $ 356.3 $ 200.9 $ 141.8 $ 4.9 $ 166.1 $ 40.5 $ 77.3 Loss from equity investees $ (0.2 ) $ — $ — $ — $ — $ — $ (0.2 ) $ — $ — Loss on extinguishments of debt $ (48.9 ) $ — $ (48.9 ) $ — $ — $ — $ — $ — $ — Interest expense $ (228.9 ) $ — $ (164.1 ) $ (37.6 ) $ (2.1 ) $ — $ (20.8 ) $ (3.6 ) $ (0.7 ) Income before income taxes $ 710.0 $ 0.2 $ 143.3 $ 163.3 $ 139.7 $ 4.9 $ 145.1 $ 36.9 $ 76.6 Net income attributable to UGI $ 364.7 $ 0.1 $ 43.2 $ 97.4 $ 83.5 $ 3.6 $ 84.2 $ 27.4 $ 25.3 Depreciation and amortization $ 400.9 $ (0.2 ) $ 190.0 $ 67.3 $ 17.1 $ 13.5 $ 90.5 $ 21.9 $ 0.8 Noncontrolling interests’ net income (loss) $ 124.1 $ — $ 75.9 $ — $ — $ — $ (0.1 ) $ 0.1 $ 48.2 Partnership Adjusted EBITDA (a) $ 543.0 Total assets $ 10,847.2 $ (136.6 ) $ 4,071.8 $ 2,743.1 $ 765.6 $ 272.6 $ 2,338.8 $ 526.3 $ 265.6 Midstream & Marketing UGI International Total Elim- inations AmeriGas Propane UGI Utilities Energy Services Electric Generation UGI France Flaga & Other Corporate & Other (b) Short-term borrowings $ 291.7 $ — $ 153.2 $ 112.5 $ 25.5 $ — $ 0.4 $ 0.1 $ — Capital expenditures $ 604.6 $ — $ 101.7 $ 262.5 $ 136.8 $ 3.6 $ 75.8 $ 24.1 $ 0.1 Investments in equity investees $ 25.9 $ — $ — $ — $ 17.4 $ — $ 4.6 $ 3.9 $ — Goodwill $ 2,989.0 $ — $ 1,978.3 $ 182.1 $ 11.6 $ — $ 723.2 $ 93.8 $ — 2015 (e) Revenues $ 6,691.1 $ (231.4 ) (c) $ 2,885.3 $ 1,041.6 $ 1,105.5 $ 75.9 $ 1,122.2 $ 686.3 $ 5.7 Cost of sales $ 3,736.5 $ (227.6 ) (c) $ 1,340.0 $ 510.8 $ 840.2 $ 32.2 $ 628.0 $ 492.0 $ 120.9 Operating income (loss) $ 834.9 $ (0.9 ) $ 427.6 $ 241.7 $ 169.6 $ 13.0 $ 75.9 $ 36.9 $ (128.9 ) Loss from equity investees $ (1.2 ) $ — $ — $ — $ — $ — $ (1.2 ) $ — $ — Interest expense $ (241.9 ) $ — $ (162.8 ) $ (41.1 ) $ (2.1 ) $ — $ (31.6 ) (d) $ (3.6 ) $ (0.7 ) Income (loss) before income taxes $ 591.8 $ (0.9 ) $ 264.8 $ 200.6 $ 167.5 $ 13.0 $ 43.1 $ 33.3 $ (129.6 ) Net income (loss) attributable to UGI $ 281.0 $ (0.6 ) $ 61.0 $ 121.1 $ 97.9 $ 9.6 $ 27.5 $ 25.2 $ (60.7 ) Depreciation and amortization $ 374.1 $ — $ 194.9 $ 63.5 $ 15.5 $ 12.5 $ 63.7 $ 23.2 $ 0.8 Noncontrolling interests’ net income (loss) $ 133.0 $ — $ 167.9 $ — $ — $ — $ — $ (0.1 ) $ (34.8 ) Partnership Adjusted EBITDA (a) $ 619.2 Total assets $ 10,514.2 $ (90.4 ) $ 4,128.4 $ 2,506.0 $ 687.6 $ 282.0 $ 2,331.8 $ 529.1 $ 139.7 Short-term borrowings $ 189.9 $ — $ 68.1 $ 71.7 $ 49.5 $ — $ 0.1 $ 0.5 $ — Capital expenditures $ 475.4 $ — $ 102.0 $ 197.7 $ 71.3 $ 16.7 $ 65.0 $ 22.5 $ 0.2 Investments in equity investees $ 16.2 $ — $ — $ — $ 6.4 $ — $ 6.0 $ 3.8 $ — Goodwill $ 2,953.4 $ — $ 1,956.0 $ 182.1 $ 11.6 $ — $ 721.4 $ 82.3 $ — 2014 (e) Revenues $ 8,277.3 $ (321.3 ) (c) $ 3,712.9 $ 1,086.9 $ 1,388.6 $ 85.1 $ 1,295.5 $ 1,026.9 $ 2.7 Cost of sales $ 5,175.7 $ (317.7 ) (c) $ 2,107.1 $ 562.9 $ 1,110.2 $ 39.6 $ 848.1 $ 809.9 $ 15.6 Operating income (loss) $ 1,005.6 $ 0.2 $ 472.0 $ 246.4 $ 178.7 $ 18.1 $ 79.1 $ 38.4 $ (27.3 ) Loss from equity investees $ (0.1 ) $ — $ — $ — $ — $ — $ (0.1 ) $ — $ — Interest expense $ (237.7 ) $ — $ (165.6 ) $ (38.5 ) $ (2.9 ) $ — $ (25.1 ) $ (4.9 ) $ (0.7 ) Income (loss) before income taxes $ 767.8 $ 0.2 $ 306.4 $ 207.9 $ 175.8 $ 18.1 $ 53.9 $ 33.5 $ (28.0 ) Net income (loss) attributable to UGI $ 337.2 $ — $ 63.0 $ 124.1 $ 104.1 $ 12.6 $ 20.6 $ 27.7 $ (14.9 ) Depreciation and amortization $ 362.9 $ — $ 197.2 $ 59.2 $ 13.5 $ 10.7 $ 54.5 $ 27.1 $ 0.7 Noncontrolling interests’ net income (loss) $ 195.4 $ — $ 195.8 $ — $ — $ — $ (0.4 ) $ — $ — Partnership Adjusted EBITDA (a) $ 664.8 Total assets $ 10,062.6 $ (86.5 ) $ 4,351.4 $ 2,352.1 $ 601.5 $ 277.7 $ 1,656.8 $ 643.6 $ 266.0 Short-term borrowings $ 210.8 $ — $ 109.0 $ 86.3 $ 7.5 $ — $ — $ 8.0 $ — Capital expenditures $ 436.4 $ — $ 113.9 $ 164.2 $ 69.2 $ 15.6 $ 50.2 $ 23.0 $ 0.3 Investments in equity investees $ 0.6 $ — $ — $ — $ — $ — $ — $ 0.6 $ — Goodwill $ 2,833.4 $ — $ 1,945.1 $ 182.1 $ 12.6 $ — $ 601.2 $ 92.4 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: 2016 2015 2014 Partnership Adjusted EBITDA $ 543.0 $ 619.2 $ 664.8 Depreciation and amortization (190.0 ) (194.9 ) (197.2 ) Interest expense (164.1 ) (162.8 ) (165.6 ) Loss on extinguishments of debt (48.9 ) — — Noncontrolling interests (i) 3.3 3.3 4.4 Income before income taxes $ 143.3 $ 264.8 $ 306.4 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Corporate & Other results principally comprise (1) revenues and expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $91.6 , $(119.1) and $(18.0) in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership. Through March 2014, Corporate & Other also had an intercompany loan. The intercompany loan interest is removed in the segment presentation. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) UGI France interest expense includes pre-tax costs of $10.3 associated with an extinguishment of debt (see Note 5 ). (e) Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Condensed Financial Information

Condensed Financial Information of Registrant (Parent Company)	12 Months Ended
	Sep. 30, 2016
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Balance Sheets	BALANCE SHEETS (Millions of dollars) September 30, 2016 2015 ASSETS Current assets: Cash and cash equivalents $ 4.8 $ 1.9 Accounts receivable - related parties 9.2 3.3 Deferred income taxes — 0.4 Prepaid expenses and other current assets 5.0 4.3 Total current assets 19.0 9.9 Investments in subsidiaries 2,832.5 2,689.7 Other assets 69.8 58.7 Total assets $ 2,921.3 $ 2,758.3 LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY Current liabilities: Accounts and notes payable $ 11.4 $ 10.9 Accrued liabilities 4.4 5.0 Total current liabilities 15.8 15.9 Noncurrent liabilities 54.6 50.4 Commitments and contingencies (Note 1) Common stockholders’ equity: Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,894,141 and 173,806,991 shares, respectively) 1,201.6 1,214.6 Retained earnings 1,840.9 1,636.9 Accumulated other comprehensive loss (154.7 ) (114.6 ) Treasury stock, at cost (36.9 ) (44.9 ) Total common stockholders’ equity 2,850.9 2,692.0 Total liabilities and common stockholders’ equity $ 2,921.3 $ 2,758.3 Note 1 — Commitments and Contingencies: In addition to the guarantees of Flaga’s debt as described in Note 5 to Consolidated Financial Statements, at September 30, 2016 , UGI Corporation had agreed to indemnify the issuers of $70.0 of surety bonds issued on behalf of certain UGI subsidiaries. UGI Corporation is authorized to guarantee up to $500.0 of obligations to suppliers and customers of Energy Services, LLC and subsidiaries of which $459.4 of such obligations were outstanding as of September 30, 2016 . UGI Corporation has guaranteed the floating to fixed rate interest rate swaps at Flaga, which obligations totaled $1.2 at September 30, 2016 .
Statements of Income	STATEMENTS OF INCOME (Millions of dollars, except per share amounts) Year Ended September 30, 2016 2015 2014 Revenues $ — $ — $ — Costs and expenses: Operating and administrative expenses 45.7 48.7 44.5 Other operating income, net (a) (45.3 ) (48.5 ) (44.2 ) 0.4 0.2 0.3 Operating loss (0.4 ) (0.2 ) (0.3 ) Intercompany interest income 0.1 0.1 0.2 Loss before income taxes (0.3 ) (0.1 ) (0.1 ) Income tax (benefit) expense (4.0 ) 1.9 2.4 Income (loss) before equity in income of unconsolidated subsidiaries 3.7 (2.0 ) (2.5 ) Equity in income of unconsolidated subsidiaries 361.0 283.0 339.7 Net income attributable to UGI Corporation $ 364.7 $ 281.0 $ 337.2 Other comprehensive (loss) income (1.1 ) 0.1 (0.7 ) Equity in other comprehensive loss of unconsolidated subsidiaries (39.0 ) (93.5 ) (28.9 ) Comprehensive income attributable to UGI Corporation $ 324.6 $ 187.6 $ 307.6 Earnings per common share: Basic $ 2.11 $ 1.62 $ 1.95 Diluted $ 2.08 $ 1.60 $ 1.92 Average common shares outstanding (thousands): Basic 173,154 173,115 172,733 Diluted 175,572 175,667 175,231 (a) UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other operating income, net” in the Statements of Income above.
Statements of Cash Flows	STATEMENTS OF CASH FLOWS (Millions of dollars) Year Ended September 30, 2016 2015 2014 NET CASH PROVIDED BY OPERATING ACTIVITIES (a) $ 195.6 $ 277.2 $ 199.7 CASH FLOWS FROM INVESTING ACTIVITIES: Net investments in unconsolidated subsidiaries (8.9 ) (104.8 ) (47.3 ) Net cash used by investing activities (8.9 ) (104.8 ) (47.3 ) CASH FLOWS FROM FINANCING ACTIVITIES: Payment of dividends on Common Stock (160.7 ) (153.5 ) (136.1 ) Purchases of UGI Common Stock (47.6 ) (34.1 ) (39.8 ) Issuances of Common Stock 24.5 16.8 23.4 Other — (0.5 ) — Net cash used by financing activities (183.8 ) (171.3 ) (152.5 ) Cash and cash equivalents increase (decrease) $ 2.9 $ 1.1 $ (0.1 ) Cash and cash equivalents: End of year $ 4.8 $ 1.9 $ 0.8 Beginning of year 1.9 0.8 0.9 Increase (decrease) $ 2.9 $ 1.1 $ (0.1 ) (a) Includes dividends received from unconsolidated subsidiaries of $193.1 , $271.6 and $186.4 for the years ended September 30, 2016 , 2015 and 2014 , respectively.

Valuation and Qualifying Accoun

Valuation and Qualifying Accounts	12 Months Ended
	Sep. 30, 2016
Valuation and Qualifying Accounts [Abstract]
Valuation and Qualifying Accounts	UGI CORPORATION AND SUBSIDIARIES SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS (Millions of dollars) Balance at beginning of year Charged (credited) to costs and expenses Other Balance at end of year Year Ended September 30, 2016 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 29.7 $ 21.7 $ (24.1 ) (1) $ 27.3 Other reserves: Deferred tax assets valuation allowance $ 131.3 $ (5.8 ) $ (8.8 ) (3) $ 114.3 (2.4 ) (4) Year Ended September 30, 2015 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 39.1 $ 31.6 $ (39.6 ) (1) $ 29.7 (1.4 ) (2) Other reserves: Deferred tax assets valuation allowance $ 59.2 $ 5.1 66.1 (3) $ 131.3 (2.6 ) (4) 3.5 (5) Year Ended September 30, 2014 Reserves deducted from assets in the consolidated balance sheet: Allowance for doubtful accounts $ 39.5 $ 43.5 $ (43.0 ) (1) $ 39.1 (0.9 ) (2) Other reserves: Deferred tax assets valuation allowance $ 97.6 $ 0.4 $ (34.0 ) (3) $ 59.2 $ (4.8 ) (4) (1) Uncollectible accounts written off, net of recoveries. (2) Effects of currency exchange. (3) Foreign tax credit valuation allowance adjustment. (4) Decrease in unusable foreign operating loss carryforwards. (5) Acquisitions

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management’s knowledge of current events, historical experience and various other assumptions that are believed to be reasonable under the circumstances. Accordingly, actual results may be different from these estimates and assumptions. Certain prior-year amounts have been reclassified to conform to the current-year presentation.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of UGI and its controlled subsidiary companies which, except for the Partnership, are majority owned. We report the public’s interests in the Partnership, and outside ownership interests in other consolidated but less than 100% -owned subsidiaries, as noncontrolling interests. We eliminate intercompany accounts and transactions when we consolidate. Entities in which we do not have control but have significant influence over operating and financial policies are accounted for by the equity method. Undistributed net earnings of our equity investees included in consolidated retained earnings were not material at September 30, 2016 and 2015 . Investments in business entities that are not publicly traded and in which we do not have significant influence over operating and financial policies are accounted for using the cost method. Such investments are recorded in other assets on the Consolidated Balance Sheets and totaled $70.1 and $70.8 at September 30, 2016 and 2015 , respectively (including $18.0 and $17.9 , respectively, associated with our approximate 3.5% interest in a private equity partnership that invests in renewable energy companies). Undivided interests in natural gas production assets and an electricity generation facility are consolidated on a proportionate basis.
Effects of Regulation	Effects of Regulation UGI Utilities accounts for the financial effects of regulation in accordance with the Financial Accounting Standards Board’s (“FASB’s”) guidance in Accounting Standards Codification (“ASC”) 980, “Regulated Operations.” In accordance with this guidance, incurred costs and estimated future expenditures that would otherwise be charged to expense are capitalized and recorded as regulatory assets when it is probable that the incurred costs or estimated future expenditures will be recovered in rates in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have not yet been incurred. Regulatory assets and liabilities are classified as current if, upon initial recognition, the entire amount related to that item will be recovered or refunded within a year of the balance sheet date. Generally, regulatory assets and regulatory liabilities are amortized into expense and income over the periods authorized by the regulator. For additional information regarding the effects of rate regulation on our utility operations, see Note 8 .
Fair Value Measurements	Fair Value Measurements The Company applies fair value measurements on a recurring and, as otherwise required under GAAP, on a nonrecurring basis. Fair value in GAAP is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements performed on a recurring basis principally relate to derivative instruments and investments held in supplemental executive retirement plan grantor trusts. GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). A level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: • Level 1 — Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date. • Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. • Level 3 — Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. We evaluate the need for credit adjustments to our derivative instrument fair values. These credit adjustments were not material to the fair values of our derivative instruments.
Derivative Instruments	Derivative Instruments Derivative instruments are reported on the Consolidated Balance Sheets at their fair values, unless the derivative instruments qualify for the normal purchase and normal sale (“NPNS”) exception under GAAP. The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated and qualifies for hedge accounting. Certain of our derivative instruments are designated and qualify as cash flow hedges and from time to time we also enter into net investment hedges. For cash flow hedges, changes in the fair values of the derivative instruments are recorded in accumulated other comprehensive income (loss) (“AOCI”) or noncontrolling interests, to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. We discontinue cash flow hedge accounting if occurrence of the forecasted transaction is determined to be no longer probable. Hedge accounting is also discontinued for derivatives that cease to be highly effective. Gains and losses on net investment hedges that relate to our foreign operations are included in AOCI until such foreign net investment is sold or liquidated. Unrealized gains and losses on substantially all of the commodity derivative instruments used by UGI Utilities (for which NPNS has not been elected) are included in regulatory assets or liabilities because it is probable such gains or losses will be recoverable from, or refundable to, customers. Effective October 1, 2014, UGI International determined on a prospective basis that it would not elect cash flow hedge accounting for its commodity derivative transactions and also de-designated its then-existing commodity derivative instruments accounted for as cash flow hedges. Also effective October 1, 2014, AmeriGas Propane de-designated its remaining commodity derivative instruments accounted for as cash flow hedges. Previously, AmeriGas Propane had discontinued cash flow hedge accounting for all commodity derivative instruments entered into beginning April 1, 2014. Midstream & Marketing has not applied cash flow hedge accounting for its commodity derivative instruments during any of the periods presented. Substantially all realized and unrealized gains and losses on commodity derivative instruments are recorded in cost of sales or revenues, as appropriate, on the Consolidated Statements of Income. Cash flows from derivative instruments, other than net investment hedges and certain cross-currency swaps, are included in cash flows from operating activities on the Consolidated Statements of Cash Flows. Cash flows from net investment hedges, if any, are included in cash flows from investing activities on the Consolidated Statements of Cash Flows. Cash flows from the interest portion of our cross-currency hedges are included in cash flow from operating activities while cash flows from the currency portion of such hedges are included in cash flow from financing activities. For a more detailed description of the derivative instruments we use, our accounting for derivatives, our objectives for using them and other information, see Note 17 .
Foreign Currency Translation	Foreign Currency Translation Balance sheets of international subsidiaries are translated into U.S. dollars using the exchange rate at the balance sheet date. Income statements and equity investee results are translated into U.S. dollars using an average exchange rate for each reporting period. Where the local currency is the functional currency, translation adjustments are recorded in other comprehensive income.
Revenue Recognition	Revenue Recognition Revenues from the sale of LPG are recognized principally upon delivery. Midstream & Marketing records revenues when energy products are delivered or services are provided to customers. Revenues from the sale of appliances and equipment are recognized at the later of sale or installation. Revenues from repair or maintenance services are recognized upon completion of services. UGI Utilities’ regulated revenues are recognized as natural gas and electricity are delivered and include estimated amounts for distribution service rendered and commodities delivered but not billed at the end of each month. We reflect the impact of Gas Utility and Electric Utility rate increases or decreases at the time they become effective. We present revenue-related taxes collected on behalf of customers and remitted to taxing authorities, principally sales and use taxes, on a net basis. Electric Utility gross receipts taxes are included in utility taxes other than income taxes on the Consolidated Statements of Income in accordance with regulatory practice.
Accounts Receivable	Accounts Receivable Accounts receivable are reported on the Consolidated Balance Sheets at the gross outstanding amount adjusted for an allowance for doubtful accounts. Accounts receivable that are acquired are initially recorded at fair value on the date of acquisition. Provisions for uncollectible accounts are established based upon our collection experience and the assessment of the collectability of specific amounts. Accounts receivable are written off in the period in which the receivable is deemed uncollectible.
LPG Delivery Expenses	LPG Delivery Expenses Expenses associated with the delivery of LPG to customers of the Partnership and our UGI International operations (including vehicle expenses, expenses of delivery personnel, vehicle repair and maintenance and general liability expenses) are classified as operating and administrative expenses on the Consolidated Statements of Income. Depreciation expense associated with the Partnership and UGI International delivery vehicles is classified in depreciation on the Consolidated Statements of Income.
Income Taxes	Income Taxes AmeriGas Partners and AmeriGas OLP are not directly subject to federal income taxes. Instead, their taxable income or loss is allocated to the individual partners. We record income taxes on (1) our share of the Partnership’s current taxable income or loss and (2) the differences between the book and tax basis of our investment in the Partnership. AmeriGas OLP has subsidiaries which operate in corporate form and are directly subject to federal and state income taxes. Legislation in certain states allows for taxation of partnership income and the accompanying financial statements reflect state income taxes resulting from such legislation. UGI Utilities records deferred income taxes in the Consolidated Statements of Income resulting from the use of accelerated tax depreciation methods based upon amounts recognized for ratemaking purposes. UGI Utilities also records a deferred income tax liability for tax benefits, principally the result of accelerated tax depreciation for state income tax purposes, that are flowed through to ratepayers when temporary differences originate and record a regulatory income tax asset for the probable increase in future revenues that will result when the temporary differences reverse. We are amortizing deferred investment tax credits related to UGI Utilities’ plant additions over the service lives of the related property. UGI Utilities reduces its deferred income tax liability for the future tax benefits that will occur when investment tax credits, which are not taxable, are amortized. We also reduce the regulatory income tax asset for the probable reduction in future revenues that will result when such deferred investment tax credits amortize. Investment tax credits associated with Midstream & Marketing’s qualifying solar energy property under the Emergency Economic Stabilization Act of 2008 are reflected in income taxes for assets placed in service after Fiscal 2011 and are amortized over the estimated useful life of the property for assets placed in service prior to Fiscal 2012. We record interest on tax deficiencies and income tax penalties in income taxes on the Consolidated Statements of Income. For Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , interest income or expense recognized in income taxes on the Consolidated Statements of Income was not material.
Earnings Per Common Share	Earnings Per Common Share Basic earnings per share attributable to UGI Corporation stockholders reflect the weighted-average number of common shares outstanding. Diluted earnings per share include the effects of dilutive stock options and common stock awards.
Cash and Cash Equivalents	Cash and Cash Equivalents All highly liquid investments with maturities of three months or less when purchased are classified as cash equivalents.
Restricted Cash	Restricted Cash Restricted cash principally represents those cash balances in our commodity futures brokerage accounts that are restricted from withdrawal.
Inventories	Inventories Our inventories are stated at the lower of cost or net realizable value. We determine cost using an average cost method for LPG, specific identification for appliances and the first-in, first-out (“FIFO”) method for all other inventories.
Property, Plant and Equipment and Related Depreciation	Property, Plant and Equipment and Related Depreciation We record property, plant and equipment at original cost. The amounts assigned to property, plant and equipment of acquired businesses are based upon estimated fair value at date of acquisition. We record depreciation expense on non-utility plant and equipment on a straight-line basis over estimated economic useful lives ranging from 10 to 40 years for buildings and improvements; 6 to 40 years for storage and customer tanks and cylinders; 25 to 40 years for electricity generation facilities; 25 to 40 years for pipeline and related assets, and 3 to 12 years for vehicles, equipment and office furniture and fixtures. Costs to install Partnership and UGI France-owned tanks, net of amounts billed to customers, are capitalized and amortized over the estimated period of benefit not exceeding 10 years. We record depreciation expense for UGI Utilities’ plant and equipment on a straight-line basis over the estimated average remaining lives of the various classes of its depreciable property. The composite annual rate for depreciable property at our Gas Utility was 2.2% in Fiscal 2016 , 2.2% in Fiscal 2015 and 2.3% in Fiscal 2014 . The composite annual rate for depreciable property at our Electric Utility was 2.5% in Fiscal 2016 , 2.5% in Fiscal 2015 and 2.5% in Fiscal 2014 . When UGI Utilities retires depreciable utility plant and equipment, we charge the original cost to accumulated depreciation for financial accounting purposes. Costs incurred to retire utility plant and equipment, net of salvage, are recorded in regulatory assets. We include in property, plant and equipment costs associated with computer software we develop or obtain for use in our businesses. We amortize computer software costs on a straight-line basis over expected periods of benefit generally not exceeding 10 years once the installed software is ready for its intended use. No depreciation expense is included in cost of sales in the Consolidated Statements of Income.
Goodwill and Intangible Assets	Goodwill and Intangible Assets In accordance with GAAP relating to intangible assets, we amortize intangible assets over their estimated useful lives unless we determine their lives to be indefinite. No amortization expense of intangible assets is included in cost of sales in the Consolidated Statements of Income (see Note 11 ). Estimated useful lives of definite-lived intangible assets, primarily consisting of customer relationships, certain tradenames and noncompete agreements, do not exceed 15 years. We review definite-lived intangible assets for impairment whenever events or changes in circumstances indicate that the associated carrying amounts may not be recoverable. Determining whether an impairment loss occurred requires comparing the carrying amount to the sum of undiscounted cash flows expected to be generated by the asset. Intangible assets with indefinite lives are not amortized but are tested for impairment annually (and more frequently if events or changes in circumstances between annual tests indicate that it is more likely than not that they are impaired) and written down to fair value, if impaired. We do not amortize goodwill, but test it at least annually for impairment at the reporting unit level. A reporting unit is an operating segment or one level below an operating segment (a component) if discrete financial information is prepared and regularly reviewed by segment management. Components are aggregated as a single reporting unit if they have similar economic characteristics. Each of our reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. During the fourth quarter of Fiscal 2016, the Company changed the measurement date for performing its annual goodwill impairment tests from September 30 to July 31. This voluntary change in accounting principle, applied prospectively, is preferable as it aligns the annual goodwill impairment test date more closely with the Company’s internal budgeting process and did not delay, accelerate or avoid an impairment of the Company’s goodwill. For certain of our reporting units with goodwill, we assess qualitative factors to determine whether it is more likely than not that the fair value of such reporting unit is less than its carrying amount. For our other reporting units with goodwill, we bypass the qualitative assessment and perform the first step of the two-step quantitative assessment by comparing the fair values of the reporting units with their carrying amounts, including goodwill. We determine fair values generally based on a weighting of income and market approaches. For purposes of the income approach, fair values are determined based upon the present value of the reporting unit’s estimated future cash flows, including an estimate of the reporting unit’s terminal value based upon these cash flows, discounted at appropriate risk-adjusted rates. We use our internal forecasts to estimate future cash flows which may include estimates of long-term future growth rates based upon our most recent reviews of the long-term outlook for each reporting unit. Cash flow estimates used to establish fair values under our income approach involve management judgments based on a broad range of information and historical results. In addition, external economic and competitive conditions can influence future performance. For purposes of the market approach, we use valuation multiples for companies comparable to our reporting units. The market approach requires judgment to determine the appropriate valuation multiples. If the carrying amount of a reporting unit exceeds its fair value, the implied fair value of goodwill is determined in the same manner as goodwill is recognized in a business combination. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to such excess.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets and Cost Basis Investments We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We evaluate recoverability based upon undiscounted future cash flows expected to be generated by such assets.
Cost Method Investments	We reduce the carrying values of our cost basis investments when we determine that a decline in fair value is other than temporary.
Refundable Tank and Cylinder Deposits	Refundable Tank and Cylinder Deposits Included in other noncurrent liabilities on our Consolidated Balance Sheets are customer paid deposits primarily on UGI France owned tanks and cylinders of $267.2 and $273.4 at September 30, 2016 and 2015 , respectively. Deposits are refundable to customers when the tanks or cylinders are returned in accordance with contract terms.
Environmental Matters	Environmental Matters We are subject to environmental laws and regulations intended to mitigate or remove the effects of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current or former operating sites. Environmental reserves are accrued when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Amounts recorded as environmental liabilities on the balance sheets represent our best estimate of costs expected to be incurred or, if no best estimate can be made, the minimum liability associated with a range of expected environmental investigation and remediation costs. Our estimated liability for environmental contamination is reduced to reflect anticipated participation of other responsible parties but is not reduced for possible recovery from insurance carriers. In those instances for which the amount and timing of cash payments associated with environmental investigation and cleanup are reliably determinable, we discount such liabilities to reflect the time value of money. We intend to pursue recovery of incurred costs through all appropriate means, including regulatory relief. UGI Gas, CPG and PNG receive ratemaking recognition of environmental investigation and remediation costs associated with their environmental sites. This ratemaking recognition balances the accumulated difference between historical costs and rate recoveries with an estimate of future costs associated with the sites. For further information, see Note 15 .
Employee Retirement Plans	Employee Retirement Plans We use a market-related value of plan assets and an expected long-term rate of return to determine the expected return on assets of our U.S. pension and other postretirement plans. The market-related value of plan assets, other than equity investments, is based upon fair values. The market-related value of equity investments is calculated by rolling forward the prior-year’s market-related value with contributions, disbursements and the expected return on plan assets. One third of the difference between the expected and the actual value is then added to or subtracted from the expected value to determine the new market-related value (see Note 7 ).
Equity-Based Compensation	Equity-Based Compensation All of our equity-based compensation, principally comprising UGI stock options, grants of UGI stock-based equity instruments and grants of AmeriGas Partners equity instruments (together with UGI stock-based equity instruments, “Units”), are measured at fair value on the grant date, date of modification or end of the period, as applicable. Compensation expense is recognized on a straight-line basis over the requisite service period. Depending upon the settlement terms of the awards, all or a portion of the fair value of equity-based awards may be presented as a liability or as equity on our Consolidated Balance Sheets. Equity-based compensation costs associated with the portion of Unit awards classified as equity are measured based upon their estimated fair value on the date of grant or modification. Equity-based compensation costs associated with the portion of Unit awards classified as liabilities are measured based upon their estimated fair value at the grant date and remeasured as of the end of each period. We have calculated a tax windfall pool using the shortcut method. We record deferred tax assets for awards that we expect will result in deductions on our income tax returns based on the amount of compensation cost recognized and the statutory tax rate in the jurisdiction in which we will receive a deduction. Differences between the deferred tax assets recognized for financial reporting purposes and the actual tax benefit received on the income tax return are recorded in Common Stock (if the tax benefit exceeds the deferred tax asset) or in the Consolidated Statements of Income (if the deferred tax asset exceeds the tax benefit and no tax windfall pool exists from previous awards). We expect to adopt new accounting guidance that simplifies and clarifies certain aspects of the accounting for and presentation of share-based payments during the first quarter of Fiscal 2017 (see Note 3). For additional information on our equity-based compensation plans and related disclosures, see Note 13 .
Accounting Changes	Adoption of New Accounting Standards Presentation of Deferred Taxes. During the first quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of deferred taxes. The new guidance amends existing guidance to require that deferred income tax liabilities and assets be classified as noncurrent in a classified balance sheet, and eliminates the prior guidance which required an entity to separate deferred tax liabilities and assets into a current amount and a noncurrent amount in a classified balance sheet. We applied this guidance prospectively and, accordingly, balance sheets prior to Fiscal 2016 have not been reclassified. Debt Issuance Costs. During the fourth quarter of Fiscal 2016, the Company adopted new accounting guidance regarding the classification of debt issuance costs. This new guidance amends existing guidance to require the presentation of debt issuance costs in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of a deferred charge. As required by the new guidance, prior period amounts have been reclassified. See Note 2 under “Deferred Debt Issuance Costs” for a description of the impact on the Consolidated Balance Sheets. Accounting Standards Not Yet Adopted Cash Flow Classification. In August 2016, the FASB issued Accounting Standards Update ("ASU") No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU provides guidance on the classification of certain cash receipts and payments in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should generally be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. In November 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows: Restricted Cash.” This ASU provides guidance on the classification of restricted cash in the statement of cash flows. The amendments in this ASU are effective for interim and annual periods beginning after December 15, 2017 (Fiscal 2019). Early adoption is permitted. The amendments in the ASU should be adopted on a retrospective basis. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance. Employee Share-Based Payments . In March 2016, the FASB issued ASU No. 2016-09, "Improvements to Employee Share-Based Payment Accounting." This ASU simplifies several aspects of the accounting for employee share-based payment transactions including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. Among other things, excess tax benefits and tax deficiencies associated with share-based awards will be recognized as income tax benefit or expense in the income statement and the tax effects of exercised or vested awards will be treated as discrete items in the reporting period in which they occur. In addition, assumed proceeds under the treasury stock method used for computing diluted shares outstanding will not include windfall tax benefits which could result in more incremental shares outstanding in the diluted shares calculation. The Company expects to adopt the new accounting guidance during the first quarter of Fiscal 2017. The amendments most likely to impact the Company, principally those requiring recognition of excess tax benefits and tax deficiencies in the income statement and the impact on the treasury stock method in computing diluted shares outstanding, will be applied prospectively. Based upon the number of share-based awards currently outstanding, we do not believe that the adoption of the new guidance will have a material impact on diluted shares outstanding. The impact of the adoption of the new guidance on our net income will depend upon the timing of the exercise or vesting of share-based awards as well as the amount of any associated excess tax benefits or deficiencies. Leases. In February 2016, the FASB issued ASU No. 2016-02, "Leases." This ASU amends existing guidance to require entities that lease assets to recognize the assets and liabilities for the rights and obligations created by those leases on the balance sheet. The new guidance also requires additional disclosures about the amount, timing and uncertainty of cash flows from leases. The amendments in this ASU are effective for annual reporting periods beginning after December 15, 2018 (Fiscal 2020). Early adoption is permitted. Lessees must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is in the process of assessing the impact on its financial statements from the adoption of the new guidance but anticipates an increase in the recognition of right-of-use assets and lease liabilities. Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The guidance provided under this ASU, as amended, supersedes the revenue recognition requirements in ASC No. 605, “Revenue Recognition,” and most industry-specific guidance included in the ASC. The standard requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance is effective for the Company for interim and annual periods beginning after December 15, 2017 (Fiscal 2019) and allows for either full retrospective adoption or modified retrospective adoption. We have not yet selected a transition method and are currently evaluating the impact of adopting this guidance on our financial statements.

Summary of Significant Accoun34

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Shares Used in Computing Basic and Diluted Earnings Per Share	In the following table, we present shares used in computing basic and diluted earnings per share for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 : (Thousands of shares) 2016 2015 2014 Weighted-average common shares outstanding for basic computation 173,154 173,115 172,733 Incremental shares issuable for stock options and common stock awards (a) 2,418 2,552 2,498 Weighted-average common shares outstanding for diluted computation 175,572 175,667 175,231 (a) For Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , there were 38 shares, 1 share and 0 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Allocation of Purchase Price	The components of the final Totalgaz purchase price allocation are as follows: Assets acquired: Cash $ 86.8 Accounts receivable (a) 170.3 Prepaid expenses and other current assets 11.0 Property, plant and equipment 375.6 Intangible assets (b) 91.3 Other assets 21.4 Total assets acquired $ 756.4 Liabilities assumed: Accounts payable 109.2 Other current liabilities 103.5 Deferred income taxes 117.5 Other noncurrent liabilities 113.4 Total liabilities assumed $ 443.6 Goodwill 183.8 Net consideration transferred (including working capital adjustments) $ 496.6 (a) Approximates the gross contractual amounts of receivables acquired. (b) Comprises $79.3 of customer relationships and $12.0 of tradenames ( $8.3 of which is subject to amortization), having average amortization periods of 15 years .
Pro Forma Income Statement and Income Per Unit	The following table presents unaudited pro forma revenues, net income attributable to UGI Corporation and earnings per share data for Fiscal 2015 and Fiscal 2014 as if the Totalgaz Acquisition had occurred on October 1, 2013. The unaudited pro forma consolidated information reflects the historical results of Totalgaz SAS and its subsidiaries after giving effect to adjustments directly attributable to the transaction, including depreciation, amortization, interest expense, intercompany eliminations and related income tax effects. The unaudited pro forma net income also reflects the effects of the issuance of the €600 term loan under France SAS’s 2015 Senior Facilities Agreement and the associated repayment of the term loan outstanding under Antargaz’ 2011 Senior Facilities Agreement as if such transactions had occurred on October 1, 2013. Amounts in the table below exclude costs associated with extinguishment of debt under Antargaz’ 2011 Senior Facilities Agreement (see Note 5 ): 2015 2014 As Reported Pro Forma Adjusted As Pro Forma Revenues $ 6,691.1 $ 7,065.8 $ 8,277.3 $ 8,999.6 Net income attributable to UGI Corporation $ 281.0 $ 341.2 $ 337.2 $ 385.5 Earnings per common share attributable to UGI Corporation stockholders: Basic $ 1.62 $ 1.97 $ 1.95 $ 2.23 Diluted $ 1.60 $ 1.94 $ 1.92 $ 2.20

Debt (Tables)

Debt (Tables)	12 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt comprises the following at September 30: 2016 2015 AmeriGas Propane: AmeriGas Partners Senior Notes: 5.875% due August 2026 $ 675.0 $ — 5.625% due May 2024 675.0 — 7.00%, due May 2022 980.8 980.8 6.75%, due May 2020 — 550.0 6.50%, due May 2021 — 270.0 6.25%, due August 2019 — 450.0 HOLP Senior Secured Notes, including unamortized premium of $0.7 and $2.5, respectively 15.2 21.0 Other 14.2 11.7 Unamortized debt issuance costs (a) (26.6 ) (21.6 ) Total AmeriGas Propane 2,333.6 2,261.9 UGI International: France SAS Senior Facilities term loan, due through April 2020 674.4 670.7 Flaga variable rate term loan, due October 2020 51.4 — Flaga variable rate term loan, due September 2018 59.1 59.1 Flaga variable rate term loan, due through August 2016 — 29.8 Flaga variable rate term loan, due October 2016 — 21.4 Other 1.4 1.8 Unamortized debt issuance costs (a) (6.7 ) (8.6 ) Total UGI International 779.6 774.2 UGI Utilities: Senior Notes: 4.12%, due September 2046 200.0 — 5.75%, due September 2016 — 175.0 4.98%, due March 2044 175.0 175.0 2.95%, due June 2026 100.0 — 6.21%, due September 2036 100.0 100.0 Medium-Term Notes: 7.37%, due October 2015 — 22.0 5.64%, due December 2015 — 50.0 6.17%, due June 2017 20.0 20.0 7.25%, due November 2017 20.0 20.0 5.67%, due January 2018 20.0 20.0 6.50%, due August 2033 20.0 20.0 6.13%, due October 2034 20.0 20.0 Unamortized debt issuance costs (a) (3.5 ) (2.2 ) Total UGI Utilities 671.5 619.8 Other 10.8 11.5 Total long-term debt 3,795.5 3,667.4 Less: current maturities (29.5 ) (257.9 ) Total long-term debt due after one year $ 3,766.0 $ 3,409.5 (a) Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 2 and Note 3 ).
Schedule of Maturities of Long-term Debt	Scheduled principal repayments of long-term debt due in fiscal years 2017 to 2021 follows: 2017 2018 2019 2020 2021 AmeriGas Propane $ 8.5 $ 6.8 $ 6.4 $ 5.7 $ 1.6 UGI Utilities 20.0 40.0 — — — UGI International 0.3 127.3 67.6 539.6 51.5 Other 0.7 0.8 0.8 0.9 0.9 Total $ 29.5 $ 174.9 $ 74.8 $ 546.2 $ 54.0
Schedule of Short-term Debt	Short-term borrowings comprise the following at September 30: 2016 2015 Credit Agreements: AmeriGas Propane $ 153.2 $ 68.1 UGI International 0.5 0.6 UGI Utilities 112.5 71.7 Midstream & Marketing — 30.0 Energy Services Receivables Facility 25.5 19.5 Total short-term borrowings $ 291.7 $ 189.9
Schedule of Receivables Facility	Information regarding the amounts of trade receivables transferred to ESFC and the amounts sold to the bank during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , as well as the balance of ESFC trade receivables at September 30, 2016 , 2015 and 2014 follows: 2016 2015 2014 Trade receivables transferred to ESFC during the year $ 756.4 $ 1,037.8 $ 1,260.6 ESFC trade receivables sold to the bank during the year 204.0 306.5 354.0 ESFC trade receivables - end of year (a) 35.7 44.1 46.4 (a) The amounts of ESFC trade receivables sold to the bank are reflected as short-term borrowings on the Consolidated Balance Sheets.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Before Income Taxes	Income before income taxes comprises the following: 2016 2015 2014 Domestic $ 518.9 $ 552.3 $ 699.2 Foreign 191.1 39.5 68.6 Total income before income taxes $ 710.0 $ 591.8 $ 767.8
Provisions for Income Taxes	The provisions for income taxes consist of the following: 2016 2015 2014 Current expense (benefit): Federal $ 44.2 $ 97.1 $ 102.4 State 20.9 32.2 30.7 Foreign 78.7 36.0 37.0 Investment tax credit — (1.2 ) (1.6 ) Total current expense 143.8 164.1 168.5 Deferred expense (benefit): Federal 81.2 28.1 61.9 State 1.3 2.9 7.8 Foreign (4.8 ) (17.0 ) (2.7 ) Investment tax credit amortization (0.3 ) (0.3 ) (0.3 ) Total deferred expense 77.4 13.7 66.7 Total income tax expense $ 221.2 $ 177.8 $ 235.2
Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate	A reconciliation from the U.S. federal statutory tax rate to our effective tax rate is as follows: 2016 2015 2014 U.S. federal statutory tax rate 35.0 % 35.0 % 35.0 % Difference in tax rate due to: Noncontrolling interests not subject to tax (6.2 ) (7.9 ) (9.0 ) State income taxes, net of federal benefit 3.0 3.3 3.4 Valuation allowance adjustments (0.9 ) 0.8 — Effects of foreign operations 0.6 0.2 1.0 Other, net (0.3 ) (1.4 ) 0.2 Effective tax rate 31.2 % 30.0 % 30.6 %
Deferred Tax Liabilities (Assets)	Deferred tax liabilities (assets) comprise the following at September 30: 2016 2015 Excess book basis over tax basis of property, plant and equipment $ 873.9 $ 798.4 Investment in AmeriGas Partners 323.2 321.4 Intangible assets and goodwill 87.1 87.1 Utility regulatory assets 148.3 117.4 Other 11.9 8.9 Gross deferred tax liabilities 1,444.4 1,333.2 Pension plan liabilities (79.7 ) (59.1 ) Employee-related benefits (63.1 ) (57.6 ) Operating loss carryforwards (31.5 ) (32.5 ) Foreign tax credit carryforwards (105.1 ) (113.8 ) Utility regulatory liabilities (13.9 ) (24.0 ) Derivative instruments (14.7 ) (11.4 ) Utility environmental liabilities (22.8 ) (6.0 ) Other (28.3 ) (17.4 ) Gross deferred tax assets (359.1 ) (321.8 ) Deferred tax assets valuation allowance 114.3 131.3 Net deferred tax liabilities $ 1,199.6 $ 1,142.7
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows: 2016 2015 2014 Unrecognized tax benefits - beginning of year $ 3.2 $ 2.4 $ 3.4 Additions for tax positions of the current year 2.2 0.9 0.7 Additions for tax positions taken in prior years 2.3 0.5 — Settlements with tax authorities/statute lapses (0.5 ) (0.6 ) (1.7 ) Unrecognized tax benefits - end of year $ 7.2 $ 3.2 $ 2.4

Employee Retirement Plans (Tabl

Employee Retirement Plans (Tables)	12 Months Ended
	Sep. 30, 2016
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Change in Pension Benefits and Other Postretirement Benefits Obligations	The following table provides a reconciliation of the projected benefit obligations (“PBOs”) of the U.S. Pension Plan and the UGI France pension plans, the accumulated benefit obligations (“ABOs”) of our other postretirement benefit plans, plan assets, and the funded status of pension and other postretirement plans as of September 30, 2016 and 2015 . ABO is the present value of benefits earned to date with benefits based upon current compensation levels. PBO is ABO increased to reflect estimated future compensation. Pension Benefits Other Postretirement Benefits 2016 2015 2016 2015 Change in benefit obligations: Benefit obligations — beginning of year $ 614.7 $ 573.6 $ 25.4 $ 21.3 Service cost 10.1 10.0 0.7 0.7 Interest cost 26.8 25.5 0.9 0.8 Actuarial loss (gain) 83.3 14.4 6.6 (2.7 ) Plan amendments — (0.6 ) (1.5 ) — Curtailment (1.4 ) (0.8 ) (0.3 ) — Totalgaz acquisition — 21.3 — 6.8 Foreign currency 0.1 (4.4 ) — (0.7 ) Benefits paid (25.9 ) (24.3 ) (0.9 ) (0.8 ) Benefit obligations — end of year $ 707.7 $ 614.7 $ 30.9 $ 25.4 Change in plan assets: Fair value of plan assets — beginning of year $ 453.8 $ 459.4 $ 12.5 $ 12.8 Actual gain (loss) on plan assets 53.4 1.1 1.3 (0.1 ) Foreign currency 0.1 (0.4 ) — — Employer contributions 11.4 11.9 0.6 0.6 Totalgaz acquisition — 6.1 — — Benefits paid (25.0 ) (24.3 ) (0.7 ) (0.8 ) Fair value of plan assets — end of year $ 493.7 $ 453.8 $ 13.7 $ 12.5 Funded status of the plans — end of year $ (214.0 ) $ (160.9 ) $ (17.2 ) $ (12.9 ) Assets (liabilities) recorded in the balance sheet: Assets in excess of liabilities — included in other noncurrent assets $ — $ — $ 4.1 $ 4.0 Unfunded liabilities — included in other noncurrent liabilities (214.0 ) (160.9 ) (21.3 ) (16.9 ) Net amount recognized $ (214.0 ) $ (160.9 ) $ (17.2 ) $ (12.9 ) Amounts recorded in UGI Corporation stockholders’ equity (pre-tax): Prior service credit $ (0.6 ) $ (0.6 ) $ (1.5 ) $ (0.1 ) Net actuarial loss 31.4 22.5 3.8 0.7 Total $ 30.8 $ 21.9 $ 2.3 $ 0.6 Amounts recorded in regulatory assets and liabilities (pre-tax): Prior service cost (credit) $ 1.2 $ 1.6 $ (2.2 ) $ (2.9 ) Net actuarial loss 181.0 138.4 2.4 2.3 Total $ 182.2 $ 140.0 $ 0.2 $ (0.6 )
Actuarial Assumptions for Domestic Plans	The expected rate of return on assets assumption is based on current and expected asset allocations as well as historical and expected returns on various categories of plan assets (as further described below). Pension Plan Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Weighted-average assumptions: Discount rate - benefit obligations 3.80 % 4.60 % 4.60 % 3.80 % 4.70 % 4.60 % Discount rate - benefit cost 4.60 % 4.60 % 5.20 % 4.70 % 4.60 % 5.10% - 5.40% Expected return on plan assets 7.55 % 7.75 % 7.75 % 5.00 % 5.00 % 5.00 % Rate of increase in salary levels 3.25 % 3.25 % 3.25 % 3.25 % 3.25 % 3.25 %
Net Periodic Pension Expense and Other Postretirement Benefit Costs	Net periodic pension expense and other postretirement benefit cost includes the following components: Pension Benefits Other Postretirement Benefits 2016 2015 2014 2016 2015 2014 Service cost $ 10.1 $ 10.0 $ 9.4 $ 0.7 $ 0.7 $ 0.5 Interest cost 26.8 25.5 26.1 0.9 0.8 0.9 Expected return on assets (32.4 ) (32.2 ) (29.7 ) (0.6 ) (0.6 ) (0.6 ) Curtailment gain (1.2 ) (0.8 ) — — — — Amortization of: Prior service cost (benefit) 0.3 0.3 0.3 (0.6 ) (0.5 ) (0.5 ) Actuarial loss 10.9 10.0 7.7 — 0.1 — Net benefit cost 14.5 12.8 13.8 0.4 0.5 0.3 Change in associated regulatory liabilities — — — 1.0 3.7 3.7 Net benefit cost after change in regulatory liabilities $ 14.5 $ 12.8 $ 13.8 $ 1.4 $ 4.2 $ 4.0
Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits	Expected payments for pension and other postretirement welfare benefits are as follows: Pension Benefits Other Postretirement Benefits Fiscal 2017 $ 28.7 $ 1.1 Fiscal 2018 $ 28.7 $ 1.1 Fiscal 2019 $ 30.0 $ 1.1 Fiscal 2020 $ 36.3 $ 1.1 Fiscal 2021 $ 39.5 $ 1.1 Fiscal 2022 - 2026 $ 189.1 $ 5.5
Schedule of Health Care Cost Trend Rates	The assumed domestic health care cost trend rates at September 30 are as follows: 2016 2015 Health care cost trend rate assumed for next year 7.25 % 7.5 % Rate to which the cost trend rate is assumed to decline (ultimate trend rate) 5.0 % 5.0 % Fiscal year that the rate reaches the ultimate trend rate 2026 2026
Pension Plans	The targets, target ranges and actual allocations for the U.S. Pension Plan and VEBA trust assets at September 30 are as follows: U.S. Pension Plan Actual Target Asset Allocation Permitted Range 2016 2015 Equity investments: Domestic 54.1 % 56.2 % 52.5 % 40.0% - 65.0% International 10.2 % 10.2 % 12.5 % 7.5% - 17.5% Total 64.3 % 66.4 % 65.0 % 60.0% - 70.0% Fixed income funds & cash equivalents 35.7 % 33.6 % 35.0 % 30.0% - 40.0% Total 100.0 % 100.0 % 100.0 % VEBA Actual Target Asset Allocation Permitted Range 2016 2015 Domestic equity investments 69.9 % 67.4 % 65.0 % 60.0% - 70.0% Fixed income funds & cash equivalents 30.1 % 32.6 % 35.0 % 30.0% - 40.0% Total 100.0 % 100.0 % 100.0 %
Fair Value of U.S. Pension Plan and VEBA Trust Assets	The fair values of the U.S. Pension Plan and VEBA trust assets by asset class and level within the fair value hierarchy, as described in Note 2 , as of September 30, 2016 and 2015 are as follows: U.S. Pension Plan Level 1 Level 2 Level 3 Total September 30, 2016: Domestic equity investments: S&P 500 Index equity mutual funds $ 158.9 $ — $ — $ 158.9 Small and midcap equity mutual funds 43.2 — — 43.2 Smallcap common stocks 11.4 — — 11.4 UGI Corporation Common Stock 37.0 — — 37.0 Total domestic equity investments 250.5 — — 250.5 International index equity mutual funds 47.3 — — 47.3 Fixed income investments: Bond index mutual funds 147.8 — — 147.8 Cash equivalents — 17.8 — 17.8 Total fixed income investments 147.8 17.8 — 165.6 Total $ 445.6 $ 17.8 $ — $ 463.4 September 30, 2015: Domestic equity investments: S&P 500 Index equity mutual funds $ 147.3 $ — $ — $ 147.3 Small and midcap equity mutual funds 40.6 — — 40.6 Smallcap common stocks 10.7 — — 10.7 UGI Corporation Common Stock 43.4 — — 43.4 Total domestic equity investments 242.0 — — 242.0 International index equity mutual funds 43.9 — — 43.9 Fixed income investments: Bond index mutual funds 140.8 — — 140.8 Cash equivalents — 4.1 — 4.1 Total fixed income investments 140.8 4.1 — 144.9 Total $ 426.7 $ 4.1 $ — $ 430.8 VEBA Level 1 Level 2 Level 3 Total September 30, 2016: S&P 500 Index equity mutual fund $ 9.6 $ — $ — $ 9.6 Bond index mutual fund 4.0 — — 4.0 Cash equivalents — 0.1 — 0.1 Total $ 13.6 $ 0.1 $ — $ 13.7 September 30, 2015: S&P 500 Index equity mutual fund $ 8.4 $ — $ — $ 8.4 Bond index mutual fund 3.8 — — 3.8 Cash equivalents — 0.3 — 0.3 Total $ 12.2 $ 0.3 $ — $ 12.5

Utility Regulatory Assets and39

Utility Regulatory Assets and Liabilities and Regulatory Matters (Tables)	12 Months Ended
	Sep. 30, 2016
Regulated Operations [Abstract]
Regulatory Assets and Liabilities Associated with Utilities	The following regulatory assets and liabilities associated with Gas Utility and Electric Utility are included in our accompanying Consolidated Balance Sheets at September 30: 2016 2015 Regulatory assets: Income taxes recoverable $ 115.7 $ 115.9 Underfunded pension and postretirement plans 183.1 140.8 Environmental costs (a) 59.4 20.0 Removal costs, net 27.9 21.2 Other 9.0 6.3 Total regulatory assets $ 395.1 $ 304.2 Regulatory liabilities (b): Postretirement benefit overcollections $ 17.5 $ 20.0 Deferred fuel and power refunds 22.3 36.6 State income tax benefits — distribution system repairs 15.1 13.3 Other 0.7 1.1 Total regulatory liabilities $ 55.6 $ 71.0 (a) Balance at September 30, 2016, includes amounts associated with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 15 ). (b) Regulatory liabilities are recorded in other current and other noncurrent liabilities on the Consolidated Balance Sheets.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Inventories	Inventories comprise the following at September 30: 2016 2015 Non-utility LPG and natural gas $ 129.8 $ 140.7 Gas Utility natural gas 29.2 37.5 Materials, supplies and other 51.3 61.7 Total inventories $ 210.3 $ 239.9

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Sep. 30, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment comprise the following at September 30: 2016 2015 Utilities: Distribution $ 2,634.2 $ 2,458.1 Transmission 93.5 90.0 General and other, including work in process 271.2 205.4 Total Utilities 2,998.9 2,753.5 Non-utility: Land 169.9 174.9 Buildings and improvements 382.2 391.4 Transportation equipment 301.7 327.9 Equipment, primarily cylinders and tanks 3,421.5 3,268.1 Electric generation 309.4 305.7 Pipeline and related assets 235.8 233.5 Other, including work in process 525.9 374.1 Total non-utility 5,346.4 5,075.6 Total property, plant and equipment $ 8,345.3 $ 7,829.1

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Sep. 30, 2016
Goodwill and Intangible Assets Disclosure [Abstract]
Changes in the Carrying Amount of Goodwill	Changes in the carrying amount of goodwill by reportable segment are as follows: UGI International AmeriGas Propane UGI Utilities Energy Services (a) UGI France Flaga & Other Total Balance September 30, 2014 $ 1,945.1 $ 182.1 $ 12.6 $ 601.2 $ 92.4 $ 2,833.4 Acquisitions 10.9 — — 186.2 2.9 200.0 Dispositions — — (1.0 ) — — (1.0 ) Foreign currency translation — — — (66.0 ) (13.0 ) (79.0 ) Balance September 30, 2015 1,956.0 182.1 11.6 721.4 82.3 2,953.4 Acquisitions 24.2 — — — 16.9 41.1 Dispositions — — — — (1.6 ) (1.6 ) Purchase price adjustments (1.9 ) — — (2.4 ) (0.2 ) (4.5 ) Foreign currency translation — — — 4.2 (3.6 ) 0.6 Balance September 30, 2016 $ 1,978.3 $ 182.1 $ 11.6 $ 723.2 $ 93.8 $ 2,989.0 (a) Prior year amounts were restated to reflect the current-year changes in the presentation of our Energy Services reportable segment (see Note 21).
Components of Intangible Assets	Intangible assets comprise the following at September 30: 2016 2015 Customer relationships, noncompete agreements and other $ 773.5 $ 761.1 Trademarks and tradenames (not subject to amortization) 131.6 131.4 Gross carrying amount 905.1 892.5 Accumulated amortization (324.8 ) (282.4 ) Intangible assets, net $ 580.3 $ 610.1

Common Stock and Equity-Based43

Common Stock and Equity-Based Compensation (Tables)	12 Months Ended
	Sep. 30, 2016
Share-based Compensation [Abstract]
Common Stock Share Activity	UGI Common Stock share activity for Fiscal 2014 , Fiscal 2015 and Fiscal 2016 follows: Issued Treasury Outstanding Balance, September 30, 2013 173,675,691 (2,032,404 ) 171,643,287 Issued: Employee and director plans 94,950 2,928,140 3,023,090 Repurchases of common stock — (1,227,654 ) (1,227,654 ) Reacquired common stock - employee and director plans — (1,164,942 ) (1,164,942 ) Balance, September 30, 2014 173,770,641 (1,496,860 ) 172,273,781 Issued: Employee and director plans 36,350 1,155,376 1,191,726 Repurchases of common stock — (1,000,000 ) (1,000,000 ) Reacquired common stock - employee and director plans — (77,004 ) (77,004 ) Balance, September 30, 2015 173,806,991 (1,418,488 ) 172,388,503 Issued: Employee and director plans 87,150 2,355,202 2,442,352 Repurchases of common stock — (1,250,000 ) (1,250,000 ) Reacquired common stock - employee and director plans — (620,406 ) (620,406 ) Balance, September 30, 2016 173,894,141 (933,692 ) 172,960,449
Stock Option Awards	Stock option transactions under equity-based compensation plans during Fiscal 2014 , Fiscal 2015 and Fiscal 2016 follow: Shares Weighted Average Option Price Total Intrinsic Value Weighted Average Contract Term (Years) Shares under option — September 30, 2013 10,193,952 $ 19.28 $ 69.6 6.8 Granted 1,665,600 $ 27.93 Canceled (86,707 ) $ 22.76 Exercised (2,815,555 ) $ 17.44 $ 37.4 Shares under option — September 30, 2014 8,957,290 $ 21.44 $ 113.3 7.0 Granted 1,336,985 $ 37.70 Canceled (85,365 ) $ 30.45 Exercised (953,533 ) $ 19.10 $ 15.4 Shares under option — September 30, 2015 9,255,377 $ 23.97 $ 104.5 6.6 Granted 1,510,625 $ 34.67 Canceled (84,213 ) $ 34.13 Exercised (2,193,338 ) $ 20.38 $ 40.1 Shares under option — September 30, 2016 8,488,451 $ 26.68 $ 157.6 6.6 Options exercisable — September 30, 2014 5,073,347 $ 19.45 Options exercisable — September 30, 2015 6,050,946 $ 20.74 Options exercisable — September 30, 2016 5,522,370 $ 22.94 $ 123.2 5.6 Options not exercisable — September 30, 2016 2,966,081 $ 33.63 $ 34.4 8.2
Additional Information Relating to Stock Options Outstanding and Exercisable	The following table presents additional information relating to stock options outstanding and exercisable at September 30, 2016 : Range of exercise prices Under $20.00 $20.01 - $25.00 $25.01 - $30.00 $30.01 - $35.00 Over $35.00 Options outstanding at September 30, 2016: Number of options 1,876,551 2,209,352 1,591,195 1,453,584 1,357,769 Weighted average remaining contractual life (in years) 4.1 5.6 7.1 9.1 8.4 Weighted average exercise price $ 18.10 $ 21.58 $ 27.44 $ 33.65 $ 38.46 Options exercisable at September 30, 2016: Number of options 1,876,551 2,073,902 1,033,454 117,050 421,413 Weighted average exercise price $ 18.10 $ 21.56 $ 27.34 $ 32.90 $ 37.73
Assumptions Used for Valuing Option Grants	The assumptions we used for valuing option grants during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 are as follows: 2016 2015 2014 Expected life of option 5.75 years 5.75 years 5.75 years Weighted average volatility 19.5% 19.5% 24.3% Weighted average dividend yield 2.6% 2.5% 2.9% Expected volatility 19.3% 19.1% -19.5% 23.7% - 24.4% Expected dividend yield 2.6% 2.5% 2.7% - 2.9% Risk free rate 1.2% - 1.9% 1.5% - 1.8% 1.8% - 2.0%
Weighted Average Assumptions Used to Determine the Fair Value of UGI Performance Unit Awards and Related Compensation Costs	The following table summarizes the weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs: Grants Awarded in Fiscal Year 2016 2015 2014 Risk free rate 1.3% 1.1% 0.8% Expected life 3 years 3 years 3 years Expected volatility 17.5% 15.9% 20.3% Dividend yield 2.7% 2.3% 2.7%
UGI Performance Unit Award Activity	The following table summarizes UGI Unit award activity for Fiscal 2016 : Total Vested Non-Vested Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) Number of UGI Units Weighted Average Grant Date Fair Value (per Unit) September 30, 2015 1,136,251 $ 23.78 803,817 $ 20.19 332,434 $ 32.28 UGI Performance Units: Granted 178,160 $ 32.64 25,291 $ 32.77 152,869 $ 32.62 Forfeited (17,356 ) $ 34.62 — $ — (17,356 ) $ 34.62 Vested — $ — 154,339 $ 28.66 (154,339 ) $ 28.66 Unit awards paid (296,687 ) $ 25.98 (296,687 ) $ 25.98 — $ — UGI Stock Units: Granted (a) 52,493 $ 34.39 39,093 $ 33.40 13,400 $ 37.29 Unit awards paid (53,778 ) $ 16.86 (53,778 ) $ 16.86 — $ — September 30, 2016 999,083 $ 25.44 672,075 $ 21.17 327,008 $ 34.21 (a) Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2015 and Fiscal 2014 were 39,801 and 44,814 , respectively.
Schedule of Payment for UGI Performance Unit and UGI Stock Unit Awards in Shares and Cash	During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the Company paid UGI Performance Unit and UGI Stock Unit awards in shares and cash as follows: 2016 2015 2014 UGI Performance Unit awards: Number of original awards granted 308,362 294,300 331,038 Fiscal year granted 2013 2012 2011 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 209,592 188,418 174,168 Cash paid $ 13.9 $ 13.3 $ 3.1 UGI Stock Unit awards: Number of original awards granted 51,037 67,419 34,639 Payment of awards: Shares of UGI Common Stock issued, net of shares withheld for taxes 39,422 44,034 22,604 Cash paid $ 0.7 $ 0.8 $ 0.4
Weighted Average Assumption Used to Determine the Fair Value of AmeriGas Performance Unit Awards and Related Compensation Costs	The following table summarizes the weighted-average assumptions used to determine the fair value of AmeriGas Performance Unit awards subject to market-based conditions and related compensation costs: Grants Awarded in Fiscal Year 2016 2015 2014 Risk-free rate 1.3% 0.9% 0.8% Expected life 3 years 3 years 3 years Expected volatility 20.6% 19.2% 21.1% Dividend yield 10.7% 6.8% 7.5%
AmeriGas Common Unit Based Award Activity	The following table summarizes AmeriGas Common Unit-based award activity for Fiscal 2016 : Total Vested Non-Vested Number of AmeriGas Partners Common Units Subject to Award Weighted Average Grant Date Fair Value (per Unit) Number of AmeriGas Partners Common Units Subject to Award Weighted Average Grant Date Fair Value (per Unit) Number of AmeriGas Partners Common Units Subject to Award Weighted Average Grant Date Fair Value (per Unit) September 30, 2015 192,583 $ 49.70 46,900 $ 44.97 145,683 $ 51.22 AmeriGas Performance Units: Granted 52,495 $ 37.65 1,267 $ 37.84 51,228 $ 37.65 Forfeited (4,994 ) $ 54.00 — $ — (4,994 ) $ 54.00 Vested — $ — 30,050 $ 43.65 (30,050 ) $ 43.65 Awards paid (34,616 ) $ 42.44 (34,616 ) $ 42.44 — $ — AmeriGas Stock Units: Granted 20,585 $ 38.65 12,785 $ 36.69 7,800 $ 41.85 Forfeited (800 ) $ 42.33 — $ — (800 ) $ 42.33 Vested — $ — 13,940 $ 49.94 (13,940 ) $ 49.94 Awards paid (14,704 ) $ 49.94 (14,704 ) $ 49.94 — $ — September 30, 2016 210,549 $ 47.24 55,622 $ 45.67 154,927 $ 47.80
AmeriGas Common Unit Based Awards in Common Units and Cash	During Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , the Partnership paid AmeriGas Performance Unit and AmeriGas Stock Unit awards in Common Units and cash as follows: 2016 2015 2014 AmeriGas Performance Unit awards: Number of Common Units subject to original awards granted 44,800 55,750 41,251 Fiscal year granted 2013 2012 2011 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 23,017 — — Cash paid $ 1.7 $ — $ — AmeriGas Stock Unit awards: Number of Common Units subject to original awards granted 20,336 42,532 72,023 Payment of awards: AmeriGas Partners Common Units issued, net of units withheld for taxes 9,272 21,509 40,842 Cash paid $ 0.4 $ 0.8 $ 1.4

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Minimum Future Payments Under Operating Leases	Minimum future payments under operating leases that have initial or remaining noncancelable terms in excess of one year are as follows: 2017 2018 2019 2020 2021 After 2021 AmeriGas Propane $ 60.6 $ 53.2 $ 48.4 $ 44.3 $ 37.0 $ 103.8 UGI Utilities 6.0 5.0 3.0 1.3 0.6 0.2 UGI International 11.4 8.8 6.4 4.2 2.8 8.0 Other 2.1 2.0 1.7 1.5 0.3 0.1 Total $ 80.1 $ 69.0 $ 59.5 $ 51.3 $ 40.7 $ 112.1
Contractual Obligations Under Supply Storage and Service Contracts	The following table presents contractual obligations under UGI Utilities, Midstream & Marketing and UGI International supply, storage and service contracts existing at September 30, 2016 : 2017 2018 2019 2020 2021 After 2021 UGI Utilities supply, storage and transportation contracts $ 115.1 $ 71.1 $ 50.8 $ 36.5 $ 35.0 $ 116.0 Midstream & Marketing supply contracts 168.4 80.4 34.0 2.3 — — UGI International supply contracts 78.7 — — — — — Total $ 362.2 $ 151.5 $ 84.8 $ 38.8 $ 35.0 $ 116.0

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents, on a gross basis, our financial assets and liabilities including both current and noncurrent portions, that are measured at fair value on a recurring basis within the fair value hierarchy as described in Note 2 , as of September 30, 2016 and 2015 : Asset (Liability) Level 1 Level 2 Level 3 Total September 30, 2016: Derivative instruments: Assets: Commodity contracts $ 28.9 $ 26.0 $ — $ 54.9 Foreign currency contracts $ — $ 17.8 $ — $ 17.8 Liabilities: Commodity contracts $ (76.8 ) $ (21.8 ) $ — $ (98.6 ) Foreign currency contracts $ — $ (2.4 ) $ — $ (2.4 ) Cross-currency swaps $ — $ (0.5 ) $ — $ (0.5 ) Interest rate contracts $ — $ (3.9 ) $ — $ (3.9 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 33.0 $ — $ — $ 33.0 September 30, 2015 Derivative instruments: Assets: Commodity contracts $ 17.4 $ 11.6 $ — $ 29.0 Foreign currency contracts $ — $ 29.1 $ — $ 29.1 Cross-currency swaps $ — $ 0.4 $ — $ 0.4 Liabilities: Commodity contracts $ (70.0 ) $ (99.0 ) $ — $ (169.0 ) Foreign currency contracts $ — $ (0.1 ) $ — $ (0.1 ) Interest rate contracts $ — $ (10.8 ) $ — $ (10.8 ) Non-qualified supplemental postretirement grantor trust investments (a) $ 30.3 $ — $ — $ 30.3 (a) Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 7 ).

Derivative Instruments and He46

Derivative Instruments and Hedging Activities (Tables)	12 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts Related to Open Derivative Contracts	The following table summarizes the gross notional amounts related to open derivative contracts at September 30, 2016 and 2015 and the final settlement date of the Company's open derivative transactions broken out by derivative type as of September 30, 2016 , excluding those derivatives that qualified for the NPNS exception: Notional Amounts (in millions) Type Units Settlements Extending Through 2016 2015 Commodity Price Risk: Regulated Utility Operations Gas Utility NYMEX natural gas futures and option contracts Dekatherms September 2017 18.4 18.9 Electric Utility forward electricity purchase contracts Kilowatt hours N/A — 136.0 FTRs & NYISO capacity contracts Kilowatt hours May 2017 58.3 277.1 Non-utility operations LPG swaps & options Gallons September 2019 396.9 516.3 Natural gas futures, forward and pipeline contracts Dekatherms December 2020 71.1 110.2 Natural gas basis swap contracts Dekatherms December 2020 118.3 75.7 NYMEX natural gas storage Dekatherms March 2017 1.9 1.9 NYMEX propane storage Gallons N/A — 2.0 Electricity long forward and futures contracts Kilowatt hours January 2020 761.2 474.3 Electricity short forward and futures contracts Kilowatt hours January 2020 264.6 297.9 FTRs & NYISO capacity contracts Kilowatt hours N/A — 82.0 Interest Rate Risk: Interest rate swaps Euro October 2020 € 645.8 € 645.8 IRPAs USD N/A $ — $ 250.0 Foreign Currency Exchange Rate Risk: Forward foreign currency exchange contracts USD September 2019 $ 314.3 $ 227.9 Cross-currency swaps USD September 2018 $ 59.1 $ 59.1
Schedule of Derivative Assets, Liabilities and the Effects of Offsetting	The following table presents the Company’s derivative assets and liabilities, as well as the effects of offsetting, as of September 30, 2016 and 2015 : 2016 2015 Derivative assets: Derivatives designated as hedging instruments: Foreign currency contracts $ 17.8 $ 29.1 Cross-currency contracts — 0.4 17.8 29.5 Derivatives subject to PGC and DS mechanisms: Commodity contracts 4.5 1.3 Derivatives not designated as hedging instruments: Commodity contracts 50.4 27.7 Total derivative assets - gross 72.7 58.5 Gross amounts offset in the balance sheet (35.0 ) (18.9 ) Cash collateral received (0.3 ) — Total derivative assets - net $ 37.4 $ 39.6 Derivative liabilities: Derivatives designated as hedging instruments: Foreign currency contracts $ (2.4 ) $ (0.1 ) Cross-currency contracts (0.5 ) — Interest rate contracts (3.9 ) (10.8 ) (6.8 ) (10.9 ) Derivatives subject to PGC and DS mechanisms: Commodity contracts (0.5 ) (5.6 ) Derivatives not designated as hedging instruments: Commodity contracts (98.1 ) (163.4 ) Total derivative liabilities - gross (105.4 ) (179.9 ) Gross amounts offset in the balance sheet 35.0 18.9 Cash collateral pledged — 8.0 Total derivative liabilities - net $ (70.4 ) $ (153.0 )
Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest	The following tables provide information on the effects of derivative instruments on the Consolidated Statements of Income and changes in AOCI and noncontrolling interests for Fiscal 2016 , Fiscal 2015 and Fiscal 2014 : Gain or (Loss) Recognized in AOCI and Noncontrolling Interests Gain or (Loss) Reclassified from AOCI and Noncontrolling Interests into Income Location of Gain or (Loss) Reclassified from Interests into Income 2016 2015 2014 2016 2015 2014 Cash Flow Hedges: Commodity contracts $ — $ — $ 50.8 $ — $ (2.2 ) $ 67.0 Cost of sales Foreign currency contracts 3.6 26.0 15.3 17.2 9.7 (3.7 ) Cost of sales Cross-currency contracts 0.1 5.4 3.1 0.4 8.5 (0.1 ) Interest expense Interest rate contracts (32.5 ) (6.6 ) (3.1 ) (4.5 ) (20.4 ) (15.9 ) Interest expense /other operating income, net Total $ (28.8 ) $ 24.8 $ 66.1 $ 13.1 $ (4.4 ) $ 47.3 Gain or (Loss) Recognized in Income Location of Recognized in Income 2016 2015 2014 Derivatives Not Designated as Hedging Instruments: Commodity contracts $ (65.0 ) $ (375.8 ) $ (36.3 ) Cost of sales Commodity contracts (2.2 ) 0.3 — Revenues Commodity contracts (0.1 ) (0.8 ) — Operating and administrative expenses / other operating income, net Total $ (67.3 ) $ (376.3 ) $ (36.3 )

Accumulated Other Comprehensi47

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	Changes in AOCI during Fiscal 2016 , Fiscal 2015 and Fiscal 2014 are as follows: Postretirement Benefit Plans Derivative Instruments Foreign Currency Total AOCI - September 30, 2013 $ (16.4 ) $ (26.9 ) $ 51.7 $ 8.4 Other comprehensive (loss) income before reclassification adjustments (after-tax) (5.2 ) 54.0 (43.0 ) 5.8 Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 1.6 (47.2 ) — (45.6 ) Reclassification adjustments tax (expense) benefit (0.6 ) 2.0 — 1.4 Reclassification adjustments (after-tax) 1.0 (45.2 ) — (44.2 ) Other comprehensive (loss) income (4.2 ) 8.8 (43.0 ) (38.4 ) Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 8.8 — 8.8 Other comprehensive (loss) income attributable to UGI (4.2 ) 17.6 (43.0 ) (29.6 ) AOCI - September 30, 2014 $ (20.6 ) $ (9.3 ) $ 8.7 $ (21.2 ) Other comprehensive (loss) income before reclassification adjustments (after-tax) (1.2 ) 16.8 (114.1 ) (98.5 ) Amounts reclassified from AOCI and noncontrolling interests: Reclassification adjustments (pre-tax) 2.2 4.4 — 6.6 Reclassification adjustments tax expense (0.8 ) (2.8 ) — (3.6 ) Reclassification adjustments (after-tax) 1.4 1.6 — 3.0 Other comprehensive income (loss) 0.2 18.4 (114.1 ) (95.5 ) Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners — 2.1 — 2.1 Other comprehensive income (loss) attributable to UGI 0.2 20.5 (114.1 ) (93.4 ) AOCI - September 30, 2015 $ (20.4 ) $ 11.2 $ (105.4 ) $ (114.6 ) Other comprehensive loss before reclassification adjustments (after-tax) (10.9 ) (16.5 ) (6.8 ) (34.2 ) Amounts reclassified from AOCI: Reclassification adjustments (pre-tax) 2.6 (13.1 ) — (10.5 ) Reclassification adjustments tax (expense) benefit (0.4 ) 5.0 — 4.6 Reclassification adjustments (after-tax) 2.2 (8.1 ) — (5.9 ) Other comprehensive loss attributable to UGI (8.7 ) (24.6 ) (6.8 ) (40.1 ) AOCI - September 30, 2016 $ (29.1 ) $ (13.4 ) $ (112.2 ) $ (154.7 )

Other Operating Income, Net (Ta

Other Operating Income, Net (Tables)	12 Months Ended
	Sep. 30, 2016
Component of Operating Income [Abstract]
Other Operating Income, Net	Other operating income, net, comprises the following: 2016 2015 2014 Interest and interest-related income $ 0.2 $ 0.8 $ 3.6 Utility non-tariff service income 2.6 4.8 2.7 Finance charges 15.2 12.7 17.5 Gains on sales of fixed assets, net 3.3 11.1 5.4 Other, net 1.1 15.0 6.9 Total other operating income, net $ 22.4 $ 44.4 $ 36.1

Quarterly Data (unaudited) (Tab

Quarterly Data (unaudited) (Tables)	12 Months Ended
	Sep. 30, 2016
Quarterly Financial Data [Abstract]
Quarterly Data (unaudited)	The following unaudited quarterly data includes adjustments (consisting only of normal recurring adjustments with the exception of those indicated below) which we consider necessary for a fair presentation unless otherwise indicated. Our quarterly results fluctuate because of the seasonal nature of our businesses and also reflect unrealized gains and losses on commodity derivative instruments used to economically hedge commodity price risk (see Note 17). December 31, March 31, June 30, September 30, 2015 2014 2016 2015 2016 (a) 2015 (b) 2016 (a) 2015 Revenues $ 1,606.6 $ 2,004.6 $ 1,972.1 $ 2,455.6 $ 1,130.8 $ 1,148.1 $ 976.2 $ 1,082.8 Operating income (loss) $ 305.5 $ 83.3 $ 615.4 $ 702.1 $ 155.7 $ 56.1 $ (88.6 ) $ (6.6 ) Loss from equity investees $ (0.1 ) $ (1.0 ) $ — $ (0.1 ) $ — $ — $ (0.1 ) $ (0.1 ) Loss on extinguishments of debt $ — $ — $ — $ — $ (37.1 ) $ — $ (11.8 ) $ — Net income (loss) including noncontrolling interests $ 167.9 $ 0.2 $ 408.0 $ 482.2 $ 28.6 $ (15.9 ) $ (115.7 ) $ (52.5 ) Net income (loss) attributable to UGI Corporation $ 114.6 $ 34.1 $ 233.2 $ 246.5 $ 60.7 $ 9.6 $ (43.8 ) $ (9.2 ) Earnings (loss) per common share attributable to UGI Corporation stockholders: Basic $ 0.66 $ 0.20 $ 1.35 $ 1.42 $ 0.35 $ 0.06 $ (0.25 ) $ (0.05 ) Diluted $ 0.65 $ 0.19 $ 1.33 $ 1.40 $ 0.34 $ 0.05 $ (0.25 ) $ (0.05 ) (a) Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5). (b) Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5 )

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Information	Midstream & Marketing UGI International Total Elim- inations AmeriGas Propane UGI Utilities Energy Services Electric Generation UGI France Flaga & Other Corporate & Other (b) 2016 Revenues $ 5,685.7 $ (143.9 ) (c) $ 2,311.8 $ 768.5 $ 813.8 $ 62.8 $ 1,344.7 $ 524.1 $ 3.9 Cost of sales $ 2,437.5 $ (141.5 ) (c) $ 864.8 $ 289.8 $ 583.7 $ 28.5 $ 597.6 $ 306.2 $ (91.6 ) Operating income $ 988.0 $ 0.2 $ 356.3 $ 200.9 $ 141.8 $ 4.9 $ 166.1 $ 40.5 $ 77.3 Loss from equity investees $ (0.2 ) $ — $ — $ — $ — $ — $ (0.2 ) $ — $ — Loss on extinguishments of debt $ (48.9 ) $ — $ (48.9 ) $ — $ — $ — $ — $ — $ — Interest expense $ (228.9 ) $ — $ (164.1 ) $ (37.6 ) $ (2.1 ) $ — $ (20.8 ) $ (3.6 ) $ (0.7 ) Income before income taxes $ 710.0 $ 0.2 $ 143.3 $ 163.3 $ 139.7 $ 4.9 $ 145.1 $ 36.9 $ 76.6 Net income attributable to UGI $ 364.7 $ 0.1 $ 43.2 $ 97.4 $ 83.5 $ 3.6 $ 84.2 $ 27.4 $ 25.3 Depreciation and amortization $ 400.9 $ (0.2 ) $ 190.0 $ 67.3 $ 17.1 $ 13.5 $ 90.5 $ 21.9 $ 0.8 Noncontrolling interests’ net income (loss) $ 124.1 $ — $ 75.9 $ — $ — $ — $ (0.1 ) $ 0.1 $ 48.2 Partnership Adjusted EBITDA (a) $ 543.0 Total assets $ 10,847.2 $ (136.6 ) $ 4,071.8 $ 2,743.1 $ 765.6 $ 272.6 $ 2,338.8 $ 526.3 $ 265.6 Midstream & Marketing UGI International Total Elim- inations AmeriGas Propane UGI Utilities Energy Services Electric Generation UGI France Flaga & Other Corporate & Other (b) Short-term borrowings $ 291.7 $ — $ 153.2 $ 112.5 $ 25.5 $ — $ 0.4 $ 0.1 $ — Capital expenditures $ 604.6 $ — $ 101.7 $ 262.5 $ 136.8 $ 3.6 $ 75.8 $ 24.1 $ 0.1 Investments in equity investees $ 25.9 $ — $ — $ — $ 17.4 $ — $ 4.6 $ 3.9 $ — Goodwill $ 2,989.0 $ — $ 1,978.3 $ 182.1 $ 11.6 $ — $ 723.2 $ 93.8 $ — 2015 (e) Revenues $ 6,691.1 $ (231.4 ) (c) $ 2,885.3 $ 1,041.6 $ 1,105.5 $ 75.9 $ 1,122.2 $ 686.3 $ 5.7 Cost of sales $ 3,736.5 $ (227.6 ) (c) $ 1,340.0 $ 510.8 $ 840.2 $ 32.2 $ 628.0 $ 492.0 $ 120.9 Operating income (loss) $ 834.9 $ (0.9 ) $ 427.6 $ 241.7 $ 169.6 $ 13.0 $ 75.9 $ 36.9 $ (128.9 ) Loss from equity investees $ (1.2 ) $ — $ — $ — $ — $ — $ (1.2 ) $ — $ — Interest expense $ (241.9 ) $ — $ (162.8 ) $ (41.1 ) $ (2.1 ) $ — $ (31.6 ) (d) $ (3.6 ) $ (0.7 ) Income (loss) before income taxes $ 591.8 $ (0.9 ) $ 264.8 $ 200.6 $ 167.5 $ 13.0 $ 43.1 $ 33.3 $ (129.6 ) Net income (loss) attributable to UGI $ 281.0 $ (0.6 ) $ 61.0 $ 121.1 $ 97.9 $ 9.6 $ 27.5 $ 25.2 $ (60.7 ) Depreciation and amortization $ 374.1 $ — $ 194.9 $ 63.5 $ 15.5 $ 12.5 $ 63.7 $ 23.2 $ 0.8 Noncontrolling interests’ net income (loss) $ 133.0 $ — $ 167.9 $ — $ — $ — $ — $ (0.1 ) $ (34.8 ) Partnership Adjusted EBITDA (a) $ 619.2 Total assets $ 10,514.2 $ (90.4 ) $ 4,128.4 $ 2,506.0 $ 687.6 $ 282.0 $ 2,331.8 $ 529.1 $ 139.7 Short-term borrowings $ 189.9 $ — $ 68.1 $ 71.7 $ 49.5 $ — $ 0.1 $ 0.5 $ — Capital expenditures $ 475.4 $ — $ 102.0 $ 197.7 $ 71.3 $ 16.7 $ 65.0 $ 22.5 $ 0.2 Investments in equity investees $ 16.2 $ — $ — $ — $ 6.4 $ — $ 6.0 $ 3.8 $ — Goodwill $ 2,953.4 $ — $ 1,956.0 $ 182.1 $ 11.6 $ — $ 721.4 $ 82.3 $ — 2014 (e) Revenues $ 8,277.3 $ (321.3 ) (c) $ 3,712.9 $ 1,086.9 $ 1,388.6 $ 85.1 $ 1,295.5 $ 1,026.9 $ 2.7 Cost of sales $ 5,175.7 $ (317.7 ) (c) $ 2,107.1 $ 562.9 $ 1,110.2 $ 39.6 $ 848.1 $ 809.9 $ 15.6 Operating income (loss) $ 1,005.6 $ 0.2 $ 472.0 $ 246.4 $ 178.7 $ 18.1 $ 79.1 $ 38.4 $ (27.3 ) Loss from equity investees $ (0.1 ) $ — $ — $ — $ — $ — $ (0.1 ) $ — $ — Interest expense $ (237.7 ) $ — $ (165.6 ) $ (38.5 ) $ (2.9 ) $ — $ (25.1 ) $ (4.9 ) $ (0.7 ) Income (loss) before income taxes $ 767.8 $ 0.2 $ 306.4 $ 207.9 $ 175.8 $ 18.1 $ 53.9 $ 33.5 $ (28.0 ) Net income (loss) attributable to UGI $ 337.2 $ — $ 63.0 $ 124.1 $ 104.1 $ 12.6 $ 20.6 $ 27.7 $ (14.9 ) Depreciation and amortization $ 362.9 $ — $ 197.2 $ 59.2 $ 13.5 $ 10.7 $ 54.5 $ 27.1 $ 0.7 Noncontrolling interests’ net income (loss) $ 195.4 $ — $ 195.8 $ — $ — $ — $ (0.4 ) $ — $ — Partnership Adjusted EBITDA (a) $ 664.8 Total assets $ 10,062.6 $ (86.5 ) $ 4,351.4 $ 2,352.1 $ 601.5 $ 277.7 $ 1,656.8 $ 643.6 $ 266.0 Short-term borrowings $ 210.8 $ — $ 109.0 $ 86.3 $ 7.5 $ — $ — $ 8.0 $ — Capital expenditures $ 436.4 $ — $ 113.9 $ 164.2 $ 69.2 $ 15.6 $ 50.2 $ 23.0 $ 0.3 Investments in equity investees $ 0.6 $ — $ — $ — $ — $ — $ — $ 0.6 $ — Goodwill $ 2,833.4 $ — $ 1,945.1 $ 182.1 $ 12.6 $ — $ 601.2 $ 92.4 $ — (a) The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: 2016 2015 2014 Partnership Adjusted EBITDA $ 543.0 $ 619.2 $ 664.8 Depreciation and amortization (190.0 ) (194.9 ) (197.2 ) Interest expense (164.1 ) (162.8 ) (165.6 ) Loss on extinguishments of debt (48.9 ) — — Noncontrolling interests (i) 3.3 3.3 4.4 Income before income taxes $ 143.3 $ 264.8 $ 306.4 (i) Principally represents the General Partner’s 1.01% interest in AmeriGas OLP. (b) Corporate & Other results principally comprise (1) revenues and expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $91.6 , $(119.1) and $(18.0) in Fiscal 2016 , Fiscal 2015 and Fiscal 2014 , respectively. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership. Through March 2014, Corporate & Other also had an intercompany loan. The intercompany loan interest is removed in the segment presentation. (c) Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane. (d) UGI France interest expense includes pre-tax costs of $10.3 associated with an extinguishment of debt (see Note 5 ). (e) Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Nature of Operations (Details)

Nature of Operations (Details)	12 Months Ended
	Sep. 30, 2016county
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General Partner held a general partner interest in AmeriGas Partners	1.00%
Percentage of our limited partnership interest in AmeriGas Partners	25.30%
Effective Ownership interest in AmeriGas OLP	27.10%
General public as limited partner interests in AmeriGas Partners	73.70%
Number of counties of operation	1

Summary of Significant Accoun52

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Ownership interests in certain subsidiaries under equity method investment, maximum	100.00%
Maturity period of highly liquid investments (in months)	3 months
Construction escrow agreement restricted cash		$ 14,300,000
Accumulated impairment losses	$ 0	0
Provision for goodwill or other intangible asset impairments	0	0	$ 0
Provisions for impairments	0	0	0
Other-than-temporary impairment of an investment in a private equity partnership pre-tax loss	0	0	$ 0
Foreign subsidiary customer deposits	$ 267,200,000	273,400,000
Property, Plant and Equipment
Estimated maximum period of capitalized and amortized costs to install partnership and antargaz-owned tanks	10 years
Estimated useful life of definite-lived intangible assets, maximum	15 years
Net deferred debt issuance costs	$ 40,800,000	$ 36,300,000
Gas Utility
Property, Plant and Equipment
Depreciation expense as percentage of related average depreciable base	2.20%	2.20%	2.30%
Electric Utility
Property, Plant and Equipment
Depreciation expense as percentage of related average depreciable base	2.50%	2.50%	2.50%
Buildings and Improvements | Minimum
Property, Plant and Equipment
Useful life (in years)	10 years
Buildings and Improvements | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Storage and Customer Tanks and Cylinders | Minimum
Property, Plant and Equipment
Useful life (in years)	6 years
Storage and Customer Tanks and Cylinders | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Electricity Generation Facilities | Minimum
Property, Plant and Equipment
Useful life (in years)	25 years
Electricity Generation Facilities | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Pipeline and Related Assets | Minimum
Property, Plant and Equipment
Useful life (in years)	25 years
Pipeline and Related Assets | Maximum
Property, Plant and Equipment
Useful life (in years)	40 years
Vehicles, Equipment and Office Furniture and Fixtures | Minimum
Property, Plant and Equipment
Useful life (in years)	3 years
Vehicles, Equipment and Office Furniture and Fixtures | Maximum
Property, Plant and Equipment
Useful life (in years)	12 years
Software Costs | Maximum
Property, Plant and Equipment
Useful life (in years)	10 years
Other Assets
Property, Plant and Equipment
Cost method investments	$ 70,100,000	$ 70,800,000
Other Assets | Private Equity Partnership That Invests in Renewable Energy Companies
Property, Plant and Equipment
Cost method investments	$ 18,000,000	17,900,000
Interest in a private equity partnership	3.50%
Long-term Debt, Including Current Maturities | Accounting Standards Update 2015-03
Property, Plant and Equipment
Net deferred debt issuance costs	$ 36,800,000	$ 32,400,000

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Shares Used in Computing Basic and Diluted Earnings Per Share (Details) - shares shares in Thousands		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Weighted-average common shares outstanding for basic computation (in shares)		173,154	173,115	172,733
Incremental shares issuable for stock options and common stock awards (in shares)	[1]	2,418	2,552	2,498
Weighted-average common shares outstanding for diluted computation (in shares)		175,572	175,667	175,231
Antidilutive securities excluded from computation of earnings per share (in shares)		38	1	0
[1]	For Fiscal 2016, Fiscal 2015 and Fiscal 2014, there were 38 shares, 1 share and 0 shares, respectively, associated with outstanding stock option awards that were not included in the computation of diluted earnings per share above because their effect was antidilutive.

Acquisitions (Details)

Acquisitions (Details) $ in Millions	May 29, 2015EUR (€)	May 29, 2015USD ($)	Nov. 30, 2015EUR (€)	Nov. 30, 2015USD ($)	Sep. 30, 2016USD ($)competitor	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)
Business Acquisition
Long-term debt					$ 3,795.5	$ 3,667.4
Number of competitors challenging agreement | competitor					2
Totalgaz SAS
Business Acquisition
Transaction related costs						16.1
Totalgaz SAS | France SAS
Business Acquisition
Cash consideration	€ 451,800,000	$ 496.6
Estimated Acquisition Date working capital	30,000,000	$ 33
Adjustment to working capital			€ 1,100,000	$ 1.2
Totalgaz SAS | France SAS | Term Loan | 2015 Senior Facilities Agreement
Business Acquisition
Long-term debt | €	€ 600,000,000
Total LPG | Flaga and AvantiGas
Business Acquisition
Cash consideration					$ 24.1
Total LPG | Flaga | Hungary
Business Acquisition
Cash consideration						17.6
Several Retail Propane Distribution Businesses | Amerigas OLP
Business Acquisition
Cash consideration					$ 37.6	$ 20.8	$ 15.7
Retail Natural Gas Marketing Business | Energy Services
Business Acquisition
Cash consideration							$ 20

Acquisitions - Allocation of Pu

Acquisitions - Allocation of Purchase Price (Details) - USD ($) $ in Millions		12 Months Ended
		Sep. 30, 2015		Sep. 30, 2016	May 29, 2015	Sep. 30, 2014	[1]
Liabilities assumed:
Goodwill		$ 2,953.4	[1]	$ 2,989		$ 2,833.4
Totalgaz SAS
Assets acquired:
Cash					$ 86.8
Accounts receivable	[2]				170.3
Prepaid expenses and other current assets					11
Property, plant & equipment					375.6
Intangible assets	[3]				91.3
Other assets					21.4
Total assets acquired					756.4
Liabilities assumed:
Accounts payable					109.2
Other current liabilities					103.5
Deferred income taxes					117.5
Other noncurrent liabilities					113.4
Total liabilities assumed					443.6
Goodwill					183.8
Net consideration transferred (including working capital adjustments)					496.6
Intangible assets acquired, tradenames					12
Average amortization period		15 years
Totalgaz SAS | Customer Relationships
Liabilities assumed:
Finite-lived intangible assets acquired					$ 79.3
Totalgaz SAS | Tradenames
Liabilities assumed:
Finite-lived intangible assets acquired				$ 8.3
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).
[2]	Approximates the gross contractual amounts of receivables acquired.
[3]	Comprises $79.3 of customer relationships and $12.0 of tradenames ($8.3 of which is subject to amortization), having average amortization periods of 15 years.

Acquisitions - Pro Forma Income

Acquisitions - Pro Forma Income Statement and Income Per Unit (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended											12 Months Ended
	Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	[2]	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
As Reported
Revenues	$ 976.2		$ 1,130.8		$ 1,972.1	$ 1,606.6	$ 1,082.8	$ 1,148.1		$ 2,455.6	$ 2,004.6	$ 5,685.7	$ 6,691.1	[3]	$ 8,277.3	[3]
Net income attributable to UGI Corporation	$ (43.8)		$ 60.7		$ 233.2	$ 114.6	$ (9.2)	$ 9.6		$ 246.5	$ 34.1	$ 364.7	$ 281	[3]	$ 337.2	[3]
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ (0.25)		$ 0.35		$ 1.35	$ 0.66	$ (0.05)	$ 0.06		$ 1.42	$ 0.20	$ 2.11	$ 1.62		$ 1.95
Diluted (in dollars per share)	$ (0.25)		$ 0.34		$ 1.33	$ 0.65	$ (0.05)	$ 0.05		$ 1.40	$ 0.19	$ 2.08	$ 1.60		$ 1.92
Pro Forma Adjusted
Revenues													$ 7,065.8		$ 8,999.6
Net income attributable to UGI Corporation													$ 341.2		$ 385.5
Earnings per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)													$ 1.97		$ 2.23
Diluted (in dollars per share)													$ 1.94		$ 2.20
[1]	Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5).
[2]	Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5)
[3]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt Instruments (Details) € in Millions, $ in Millions		Sep. 30, 2016USD ($)	Jun. 30, 2016	Oct. 31, 2015EUR (€)	Oct. 31, 2015USD ($)	Sep. 30, 2015EUR (€)	Sep. 30, 2015USD ($)	May 29, 2015EUR (€)	May 29, 2015USD ($)	Apr. 30, 2015EUR (€)
Debt Instrument
Long-term debt, gross		$ 3,832.3					$ 3,699.8
Unamortized debt issuance costs		(40.8)					(36.3)
Total long-term debt		3,795.5					3,667.4
Less: current maturities		(29.5)					(257.9)
Total long-term debt due after one year		3,766					3,409.5
AmeriGas Propane
Debt Instrument
Unamortized debt issuance costs	[1]	(26.6)					(21.6)
Total long-term debt		2,333.6					2,261.9
AmeriGas Propane | Other
Debt Instrument
Long-term debt, gross		14.2					11.7
AmeriGas Propane | Senior Notes | 5.875% Senior Notes, due 2026
Debt Instrument
Long-term debt, gross		$ 675					0
Stated interest rate (percentage)		5.875%	5.875%
AmeriGas Propane | Senior Notes | 5.625% Senior Notes, due 2024
Debt Instrument
Long-term debt, gross		$ 675					0
Stated interest rate (percentage)		5.625%	5.625%
AmeriGas Propane | Senior Notes | 7.00% Senior Notes, due 2022
Debt Instrument
Long-term debt, gross		$ 980.8					$ 980.8
Stated interest rate (percentage)		7.00%				7.00%	7.00%
AmeriGas Propane | Senior Notes | 6.75% Senior Notes, due 2020
Debt Instrument
Long-term debt, gross		$ 0					$ 550
Stated interest rate (percentage)		6.75%				6.75%	6.75%
AmeriGas Propane | Senior Notes | 6.50% Senior Notes, due 2021
Debt Instrument
Long-term debt, gross		$ 0					$ 270
Stated interest rate (percentage)		6.50%				6.50%	6.50%
AmeriGas Propane | Senior Notes | 6.25% Senior Notes, due 2019
Debt Instrument
Long-term debt, gross		$ 0					$ 450
Stated interest rate (percentage)		6.25%				6.25%	6.25%
AmeriGas Propane | Senior Secured Notes | HOLP Senior Secured Notes
Debt Instrument
Long-term debt, gross		$ 15.2					$ 21
Unamortized premium		0.7					2.5
UGI International
Debt Instrument
Unamortized debt issuance costs	[1]	(6.7)					(8.6)
Total long-term debt		779.6					774.2
UGI International | Other | Other
Debt Instrument
Long-term debt, gross		1.4					1.8
France SAS | Term Loan | France SAS Senior Facilities term loan, due through April 2020
Debt Instrument
Long-term debt, gross		674.4					670.7
Total long-term debt								€ 600	$ 659.6	€ 600
Flaga | Term Loan | Flaga Term Loan, due October 2020
Debt Instrument
Long-term debt, gross		51.4					0
Flaga | Term Loan | Flaga Term Loan, due September 2018
Debt Instrument
Long-term debt, gross		59.1					59.1
Flaga | Term Loan | Flaga Term Loan, due through August 2016
Debt Instrument
Long-term debt, gross		0		€ 26.7	$ 29.8	€ 26.7	29.8
Flaga | Term Loan | Flaga Term Loan, due October 2016
Debt Instrument
Long-term debt, gross		0		€ 19.1	$ 21.4	€ 19.1	21.4
UGI Utilities
Debt Instrument
Unamortized debt issuance costs	[1]	(3.5)					(2.2)
Total long-term debt		671.5					619.8
UGI Utilities | Senior Notes | 4.12% Senior Notes, due 2046
Debt Instrument
Long-term debt, gross		$ 200					0
Stated interest rate (percentage)		4.12%
UGI Utilities | Senior Notes | 5.75% Senior Notes, due 2016
Debt Instrument
Long-term debt, gross		$ 0					$ 175
Stated interest rate (percentage)						5.75%	5.75%
UGI Utilities | Senior Notes | 4.98% Senior Notes, due 2044
Debt Instrument
Long-term debt, gross		$ 175					$ 175
Stated interest rate (percentage)		4.98%				4.98%	4.98%
UGI Utilities | Senior Notes | 2.95% Senior Notes, due 2026
Debt Instrument
Long-term debt, gross		$ 100					$ 0
Stated interest rate (percentage)		2.95%	2.95%
UGI Utilities | Senior Notes | 6.21% Senior Notes, due 2036
Debt Instrument
Long-term debt, gross		$ 100					$ 100
Stated interest rate (percentage)		6.21%				6.21%	6.21%
UGI Utilities | Medium-term Notes | 7.37% Medium-term Notes, due October 2015
Debt Instrument
Long-term debt, gross		$ 0					$ 22
Stated interest rate (percentage)						7.37%	7.37%
UGI Utilities | Medium-term Notes | 5.64% Medium-term Notes, due December 2015
Debt Instrument
Long-term debt, gross		0					$ 50
Stated interest rate (percentage)						5.64%	5.64%
UGI Utilities | Medium-term Notes | 6.17% Medium-term Notes, due June 2017
Debt Instrument
Long-term debt, gross		$ 20					$ 20
Stated interest rate (percentage)		6.17%				6.17%	6.17%
UGI Utilities | Medium-term Notes | 7.25% Medium-term Notes, due November 2017
Debt Instrument
Long-term debt, gross		$ 20					$ 20
Stated interest rate (percentage)		7.25%				7.25%	7.25%
UGI Utilities | Medium-term Notes | 5.67% Medium-term Notes, due 2018
Debt Instrument
Long-term debt, gross		$ 20					$ 20
Stated interest rate (percentage)		5.67%				5.67%	5.67%
UGI Utilities | Medium-term Notes | 6.50% Medium-term Notes, due 2033
Debt Instrument
Long-term debt, gross		$ 20					$ 20
Stated interest rate (percentage)		6.50%				6.50%	6.50%
UGI Utilities | Medium-term Notes | 6.13% Medium-term Notes, due 2034
Debt Instrument
Long-term debt, gross		$ 20					$ 20
Stated interest rate (percentage)		6.13%				6.13%	6.13%
Other
Debt Instrument
Total long-term debt		$ 10.8					$ 11.5
[1]	Prior-year amounts reflect the retrospective impact from the adoption of new accounting guidance regarding the classification of debt issuance costs (see Note 2 and Note 3).

Debt - Schedule of Maturities o

Debt - Schedule of Maturities of Long-term Debt (Details) $ in Millions	Sep. 30, 2016USD ($)
Debt Instrument
2,017	$ 29.5
2,018	174.9
2,019	74.8
2,020	546.2
2,021	54
AmeriGas Propane
Debt Instrument
2,017	8.5
2,018	6.8
2,019	6.4
2,020	5.7
2,021	1.6
UGI Utilities
Debt Instrument
2,017	20
2,018	40
2,019	0
2,020	0
2,021	0
UGI International
Debt Instrument
2,017	0.3
2,018	127.3
2,019	67.6
2,020	539.6
2,021	51.5
Other
Debt Instrument
2,017	0.7
2,018	0.8
2,019	0.8
2,020	0.9
2,021	$ 0.9

Debt - Schedule of Short-term D

Debt - Schedule of Short-term Debt (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Short-term Debt
Short-term debt	$ 291.7	$ 189.9
AmeriGas Propane Credit Agreement
Short-term Debt
Short-term debt	153.2	68.1
UGI International Credit Agreement
Short-term Debt
Short-term debt	0.5	0.6
2015 UGI Utilities Credit Agreement
Short-term Debt
Short-term debt	112.5	71.7
Midstream and Marketing
Short-term Debt
Short-term debt	0	30
Energy Services Receivables Facility
Short-term Debt
Short-term debt	$ 25.5	$ 19.5

Debt - AmeriGas Propane (Detail

Debt - AmeriGas Propane (Details) - USD ($)	3 Months Ended											12 Months Ended
	Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	[2]	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Debt Instrument
Loss on extinguishments of debt	$ 11,800,000	[1]	$ 37,100,000	[1]	$ 0	$ 0	$ 0	$ 0		$ 0	$ 0	$ 48,900,000	$ 0	$ 0
AmeriGas Propane
Debt Instrument
Aggregate principal amount of tendered notes redeemed												1,270,000,000
Loss on extinguishments of debt												48,900,000
Tender premiums												38,900,000
Write off of debt issuance costs												$ 9,300,000
AmeriGas Propane | Senior Notes | 5.625% Senior Notes, due 2024
Debt Instrument
Aggregate principal amount			$ 675,000,000
Stated interest rate (percentage)	5.625%		5.625%									5.625%
AmeriGas Propane | Senior Notes | 5.875% Senior Notes, due 2026
Debt Instrument
Aggregate principal amount			$ 675,000,000
Stated interest rate (percentage)	5.875%		5.875%									5.875%
AmeriGas Propane | Senior Notes | 6.50% Senior Notes, due 2021
Debt Instrument
Stated interest rate (percentage)	6.50%						6.50%					6.50%	6.50%
AmeriGas Propane | Senior Notes | 6.75% Senior Notes, due 2020
Debt Instrument
Stated interest rate (percentage)	6.75%											6.75%
AmeriGas Propane | Senior Notes | 6.25% Senior Notes, due 2019
Debt Instrument
Stated interest rate (percentage)	6.25%						6.25%					6.25%	6.25%
AmeriGas Propane | Senior Secured Notes | HOLP Senior Secured Notes
Debt Instrument
Effective interest rate (percentage)	6.75%											6.75%
AmeriGas Propane | Line of Credit | AmeriGas Credit Agreement
Debt Instrument
Maximum borrowing capacity	$ 525,000,000											$ 525,000,000
Weighted-average interest rate	2.79%						2.20%					2.79%	2.20%
AmeriGas Propane | Line of Credit | AmeriGas Credit Agreement | Federal Funds Rate
Debt Instrument
Basis spread on variable rate (percentage)												0.50%
AmeriGas Propane | Line of Credit | Minimum | AmeriGas Credit Agreement
Debt Instrument
Facility fee												0.30%
AmeriGas Propane | Line of Credit | Minimum | AmeriGas Credit Agreement | Base Rate
Debt Instrument
Basis spread on variable rate (percentage)												0.50%
AmeriGas Propane | Line of Credit | Minimum | AmeriGas Credit Agreement | Eurodollar
Debt Instrument
Basis spread on variable rate (percentage)												1.50%
AmeriGas Propane | Line of Credit | Maximum | AmeriGas Credit Agreement
Debt Instrument
Facility fee												0.45%
AmeriGas Propane | Line of Credit | Maximum | AmeriGas Credit Agreement | Base Rate
Debt Instrument
Basis spread on variable rate (percentage)												1.50%
AmeriGas Propane | Line of Credit | Maximum | AmeriGas Credit Agreement | Eurodollar
Debt Instrument
Basis spread on variable rate (percentage)												2.50%
AmeriGas Propane | Letter of Credit | AmeriGas Credit Agreement
Debt Instrument
Maximum borrowing capacity	$ 125,000,000											$ 125,000,000
Issued and Outstanding letters of credit	$ 67,200,000						$ 64,700,000					$ 67,200,000	$ 64,700,000
[1]	Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5).
[2]	Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5)

Debt - UGI International (Detai

Debt - UGI International (Details) $ in Millions	Apr. 30, 2015EUR (€)	Oct. 31, 2015EUR (€)	Sep. 30, 2016EUR (€)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Oct. 31, 2015USD ($)	Sep. 30, 2015EUR (€)	Sep. 30, 2015USD ($)	May 29, 2015EUR (€)	May 29, 2015USD ($)
Debt Instrument
Long-term debt | $						$ 3,795.5			$ 3,667.4
Principal repayments due April 30, 2018 | $						74.8
Principal repayments due April 30, 2019 | $						546.2
Principal repayments due April 30, 2020 | $						54
Long-term debt, gross | $						$ 3,832.3			3,699.8
Interest Rate Swap | Interest Expense
Debt Instrument
Loss on interest rate swaps | $					$ 9
France SAS | 2015 Senior Facilities Agreement
Debt Instrument
Debt instrument term (in years)	5 years
Ratio of net debt to EBITDA			3.50	3.50
France SAS | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Variable interest rate floor (percentage)			0.00%	0.00%
France SAS | Interest Expense | 2011 Senior Facilities Agreement
Debt Instrument
Write off of debt issuance costs | $				$ 1.3
France SAS | AGZ Holding | 2011 Senior Facilities Agreement
Debt Instrument
Repayments of debt			€ 342,000,000
France SAS | Interest Rate Swap | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Underlying fixed interest rate (percentage)			0.18%			0.18%
France SAS | Interest Rate Swap | Interest Expense | 2011 Senior Facilities Agreement
Debt Instrument
Loss on interest rate swaps | $				$ 9
France SAS | Minimum | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)			1.60%	1.60%
France SAS | Maximum | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)			2.70%	2.70%
France SAS | Revolving Credit Facility | Minimum | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)	1.45%
France SAS | Revolving Credit Facility | Maximum | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)	2.55%
France SAS | Term Loan | 2015 Senior Facilities Agreement
Debt Instrument
Long-term debt	€ 600,000,000									€ 600,000,000	$ 659.6
Principal repayments due April 30, 2018			€ 60,000,000
Principal repayments due April 30, 2019			60,000,000
Principal repayments due April 30, 2020			€ 480,000,000
Long-term debt, gross | $						$ 674.4			$ 670.7
France SAS | Term Loan | 2015 Senior Facilities Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)			1.90%	1.90%
Effective interest rate (percentage)			2.10%			2.10%		2.70%	2.70%
France SAS | Term Loan | 2011 Senior Facilities Agreement
Debt Instrument
Pretax loss on early extinguishment of debt | $				$ 10.3
France SAS | Line of Credit | Revolving Credit Facility | 2015 Senior Facilities Agreement
Debt Instrument
Maximum borrowing capacity	60,000,000
Flaga | Term Loan | Flaga Credit Facility Agreement
Debt Instrument
Effective interest rate (percentage)			2.11%			2.11%
Flaga | Term Loan | Flaga Term Loan, due October 2016
Debt Instrument
Effective interest rate (percentage)								3.40%	3.40%
Long-term debt, gross		€ 19,100,000				$ 0	$ 21.4	€ 19,100,000	$ 21.4
Flaga | Term Loan | Flaga Term Loan, due through August 2016
Debt Instrument
Effective interest rate (percentage)								4.21%	4.21%
Long-term debt, gross		26,700,000				0	29.8	€ 26,700,000	$ 29.8
Flaga | Term Loan | Flaga Term Loan due through September 2016
Debt Instrument
Long-term debt, gross | $									52
Flaga | Term Loan | Flaga Term Loan, due September 2018
Debt Instrument
Long-term debt, gross | $						$ 59.1			$ 59.1
Flaga | Term Loan | Flaga Term Loan, due September 2018 | One-Month LIBOR
Debt Instrument
Basis spread on variable rate (percentage)			1.125%	1.125%
Flaga | Term Loan | Interest Rate Swap | Flaga Credit Facility Agreement | Three-Month EURIBOR
Debt Instrument
Underlying fixed interest rate (percentage)			0.23%			0.23%
Flaga | Term Loan | Cross Currency Contracts | Flaga Term Loan, due September 2018 | One-Month LIBOR
Debt Instrument
Effective interest rate (percentage)			0.87%			0.87%		0.87%	0.87%
Flaga | Term Loan | Minimum | Flaga Credit Facility Agreement | Three-Month EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)			1.20%	1.20%
Flaga | Term Loan | Maximum | Flaga Credit Facility Agreement | Three-Month EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)			2.60%	2.60%
Flaga | Term Loan | Flaga Credit Facility Agreement
Debt Instrument
Maximum borrowing capacity		45,800,000
Long-term debt, gross		45,800,000					$ 51.4
Flaga | Line of Credit | Flaga Credit Facility Agreement
Debt Instrument
Maximum borrowing capacity		100,800,000
Flaga | Line of Credit | Flaga Multi-Currency Working Capital Facility
Debt Instrument
Maximum borrowing capacity			€ 46,000,000
Flaga | Line of Credit | Revolving Credit Facility | Flaga Credit Facility Agreement
Debt Instrument
Maximum borrowing capacity		€ 25,000,000
Facility fee		30.00%
Flaga | Line of Credit | Revolving Credit Facility | Minimum | Flaga Credit Facility Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)		1.45%
Flaga | Line of Credit | Revolving Credit Facility | Maximum | Flaga Credit Facility Agreement | EURIBOR
Debt Instrument
Basis spread on variable rate (percentage)		3.65%
Flaga | Overdraft Facility | Flaga Credit Facility Agreement
Debt Instrument
Maximum borrowing capacity		€ 5,000,000
Flaga | Guarantee Facility | Flaga Credit Facility Agreement
Debt Instrument
Maximum borrowing capacity		€ 25,000,000
Antargaz | Revolving Credit Facility | 2015 Senior Facilities Agreement
Debt Instrument
Maximum borrowing capacity										€ 30,000,000
Finagaz | Revolving Credit Facility | 2015 Senior Facilities Agreement
Debt Instrument
Maximum borrowing capacity	€ 30,000,000

Debt - UGI Utilities (Details)

Debt - UGI Utilities (Details) - UGI Utilities	12 Months Ended
	Sep. 30, 2016USD ($)	Oct. 31, 2016USD ($)	Jun. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Senior Notes
Debt Instrument
Ratio of Consolidated Debt to Consolidated Total Capital	0.65
2015 UGI Utilities Credit Agreement
Debt Instrument
Ratio of Consolidated Debt to Consolidated Total Capital	0.65
2015 UGI Utilities Credit Agreement | Line of Credit
Debt Instrument
Maximum borrowing capacity	$ 300,000,000
Weighted-average interest rate	1.42%			1.07%
Letters of Credit Outstanding, Amount	$ 2,000,000			$ 2,000,000
2015 UGI Utilities Credit Agreement | Line of Credit | Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument
Basis spread on variable rate (percentage)	0.00%
2015 UGI Utilities Credit Agreement | Line of Credit | Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument
Basis spread on variable rate (percentage)	1.75%
2015 UGI Utilities Credit Agreement | Letter of Credit
Debt Instrument
Maximum borrowing capacity	$ 100,000,000
2.95% Senior Notes, due 2026 | Senior Notes
Debt Instrument
Aggregate principal amount			$ 100,000,000
Stated interest rate (percentage)	2.95%		2.95%
4.12% Senior Notes, due 2046 | Senior Notes
Debt Instrument
Aggregate principal amount	$ 200,000,000
Stated interest rate (percentage)	4.12%
4.12% Senior Notes, due 2046 | Senior Notes | Subsequent Event
Debt Instrument
Aggregate principal amount		$ 100,000,000
Stated interest rate (percentage)		4.12%
5.75% Senior Notes, due 2016 | Senior Notes
Debt Instrument
Stated interest rate (percentage)				5.75%
7.37% Medium-term Notes, due October 2015 | Medium-term Notes
Debt Instrument
Stated interest rate (percentage)				7.37%
5.64% Medium-term Notes, due December 2015 | Medium-term Notes
Debt Instrument
Stated interest rate (percentage)				5.64%

Debt - Energy Services (Details

Debt - Energy Services (Details) - Energy Services	1 Months Ended	6 Months Ended
	Feb. 29, 2016USD ($)	Oct. 31, 2016USD ($)	Apr. 30, 2016USD ($)	Sep. 30, 2016	Sep. 30, 2015
Energy Services Credit Agreement
Debt Instrument
Maximum ratio of Total Indebtedness to EBITDA				3.50
Minimum ratio of EBITDA to interest expense				3.50
Energy Services Receivables Facility | Receivables Facility
Debt Instrument
Maximum borrowing capacity			$ 150,000,000
Energy Services Receivables Facility | Receivables Facility | Subsequent Event
Debt Instrument
Maximum borrowing capacity		$ 75,000,000
Line of Credit | Energy Services Credit Agreement
Debt Instrument
Maximum borrowing capacity	$ 240,000,000
Basis spread on variable rate (percentage)	2.25%
Weighted-average interest rate					2.75%
Line of Credit | Energy Services Credit Agreement | Maximum
Debt Instrument
Ratio of Consolidated Indebtedness to EBITDA	3
Line of Credit | Energy Services Credit Agreement | Federal Funds Rate
Debt Instrument
Basis spread on variable rate (percentage)	0.50%
Line of Credit | Energy Services Credit Agreement | London Interbank Offered Rate (LIBOR)
Debt Instrument
Basis spread on variable rate (percentage)	1.00%
Line of Credit | Energy Services Credit Agreement | Letter of Credit
Debt Instrument
Maximum borrowing capacity	$ 50,000,000

Debt - Schedule of Receivables

Debt - Schedule of Receivables Facility (Details) - Energy Services - Receivables Facility - Energy Services Receivables Facility - USD ($) $ in Millions		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Short-term Debt
Trade receivables transferred to ESFC during the year		$ 756.4	$ 1,037.8	$ 1,260.6
ESFC trade receivables sold to the bank during the year		204	306.5	354
ESFC trade receivables - end of year	[1]	$ 35.7	$ 44.1	$ 46.4
[1]	The amounts of ESFC trade receivables sold to the bank are reflected as short-term borrowings on the Consolidated Balance Sheets.

Debt - Restricted Net Assets (D

Debt - Restricted Net Assets (Details) $ in Millions	Sep. 30, 2016USD ($)
UGI Utilities | Senior Notes | 4.98% Senior Notes, due March 2044
Debt Instrument
Amount of net assets restricted from transfer to parent company under different agreements	$ 1,600

Income Taxes - Income Before In

Income Taxes - Income Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
Income Tax Disclosure [Abstract]
Domestic	$ 518.9	$ 552.3		$ 699.2
Foreign	191.1	39.5		68.6
Income before income taxes	$ 710	$ 591.8	[1]	$ 767.8	[1]
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Income Taxes - Provisions for I

Income Taxes - Provisions for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Current expense (benefit):
Federal	$ 44.2	$ 97.1	$ 102.4
State	20.9	32.2	30.7
Foreign	78.7	36	37
Investment tax credit	0	(1.2)	(1.6)
Total current expense	143.8	164.1	168.5
Deferred expense (benefit):
Federal	81.2	28.1	61.9
State	1.3	2.9	7.8
Foreign	(4.8)	(17)	(2.7)
Investment tax credit amortization	(0.3)	(0.3)	(0.3)
Total deferred expense	77.4	13.7	66.7
Total income tax expense	$ 221.2	$ 177.8	$ 235.2

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2013	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Income Taxes
Foreign tax credits		$ 25.6	$ 63	$ 12.1
Undistributed earnings of foreign subsidiaries		81.7
Deferred tax assets relating to operating loss carryforwards		31.5	32.5
Valuation allowance provided for deferred tax assets related to state net operating loss carryforwards and other state deferred tax assets of certain subsidiaries		0.2
Increase (decrease) in valuation allowance		(17)
Unrecognized income tax benefits		7.2	3.2	2.4	$ 3.4
Accrued interest included in unrecognized income tax benefits		0.3
Unrecognized tax benefits if recognized would impact the reported effective tax rate		5.8
Accrued Interest Included
Income Taxes
Unrecognized income tax benefits		7.2
State Operating Loss Carryforwards
Income Taxes
Increase (decrease) in valuation allowance		(5.5)
Foreign Tax Credits
Income Taxes
Increase (decrease) in valuation allowance		(8.8)
Foreign Operating Loss Carryforwards
Income Taxes
Increase (decrease) in valuation allowance		(2)
State Operating Loss Benefits
Income Taxes
Increase (decrease) in valuation allowance		(6.2)
Foreign Country
Income Taxes
Foreign tax credit carryforwards		105.1
State and Local Jurisdiction
Income Taxes
Decrease in income tax expense due to state tax flow through of accelerated depreciation		1.3	1.5	$ 2
Operating loss carryforwards		179.4
Deferred tax assets and associated valuation allowance for unrealized state tax benefits for equity compensation deductions		7.7	$ 6.5
UGI International Holdings BV
Income Taxes
Deferred tax assets relating to operating loss carryforwards		0.6
UGI International Holdings BV | Foreign Country
Income Taxes
Operating loss carryforwards		2.5
AmeriGas Propane
Income Taxes
Operating loss carryforwards		22.4
Deferred tax assets relating to operating loss carryforwards		8.6
Other Subsidiaries
Income Taxes
Deferred tax assets relating to operating loss carryforwards		5
UGI International
Income Taxes
Valuation allowance operating loss carryforwards		9
Flaga
Income Taxes
Deferred tax assets relating to operating loss carryforwards		9.7
Flaga | Foreign Country
Income Taxes
Operating loss carryforwards		52.4
UGI France
Income Taxes
Deferred tax assets relating to operating loss carryforwards		7.6
UGI France | Foreign Country
Income Taxes
Operating loss carryforwards		$ 21.4
France | UGI France
Income Taxes
Income tax expense	$ 5.7

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of U.S. Federal Statutory Tax Rate to Effective Tax Rate (Details)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Income Tax Disclosure [Abstract]
U.S. federal statutory tax rate	35.00%	35.00%	35.00%
Difference in tax rate due to:
Noncontrolling interests not subject to tax	(6.20%)	(7.90%)	(9.00%)
State income taxes, net of federal benefit	3.00%	3.30%	3.40%
Valuation allowance adjustments	(0.90%)	0.80%	0.00%
Effects of foreign operations	0.60%	0.20%	1.00%
Other, net	(0.30%)	(1.40%)	0.20%
Effective tax rate	31.20%	30.00%	30.60%

Income Taxes - Deferred Tax Lia

Income Taxes - Deferred Tax Liabilities (Assets) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Excess book basis over tax basis of property, plant and equipment	$ 873.9	$ 798.4
Investment in AmeriGas Partners	323.2	321.4
Intangible assets and goodwill	87.1	87.1
Utility regulatory assets	148.3	117.4
Other	11.9	8.9
Gross deferred tax liabilities	1,444.4	1,333.2
Pension plan liabilities	(79.7)	(59.1)
Employee-related benefits	(63.1)	(57.6)
Operating loss carryforwards	(31.5)	(32.5)
Foreign tax credit carryforwards	(105.1)	(113.8)
Utility regulatory liabilities	(13.9)	(24)
Derivative instruments	(14.7)	(11.4)
Utility environmental liabilities	(22.8)	(6)
Other	(28.3)	(17.4)
Gross deferred tax assets	(359.1)	(321.8)
Deferred tax assets valuation allowance	114.3	131.3
Net deferred tax liabilities	$ 1,199.6	$ 1,142.7

Income Taxes - Reconciliation71

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefits - beginning of year	$ 3.2	$ 2.4	$ 3.4
Additions for tax positions of the current year	2.2	0.9	0.7
Additions for tax positions taken in prior years	2.3	0.5	0
Settlements with tax authorities/statute lapses	(0.5)	(0.6)	(1.7)
Unrecognized tax benefits - end of year	$ 7.2	$ 3.2	$ 2.4

Employee Retirement Plans - Cha

Employee Retirement Plans - Change in Pension Benefits and Other Postretirement Benefits Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
Net actuarial loss	$ 13	$ 10.1
Pension Benefit
Change in benefit obligations:
Benefit obligations — beginning of year	614.7	573.6
Service cost	10.1	10	$ 9.4
Interest cost	26.8	25.5	26.1
Actuarial loss (gain)	83.3	14.4
Plan amendments	0	(0.6)
Curtailment	(1.4)	(0.8)
Totalgaz acquisition	0	21.3
Foreign currency	0.1	(4.4)
Benefits paid	(25.9)	(24.3)
Benefit obligations — end of year	707.7	614.7	573.6
Change in plan assets:
Fair value of plan assets — beginning of year	453.8	459.4
Actual gain (loss) on plan assets	53.4	1.1
Foreign currency	0.1	(0.4)
Employer contributions	11.4	11.9
Totalgaz acquisition	0	6.1
Benefits paid	(25)	(24.3)
Fair value of plan assets — end of year	493.7	453.8	459.4
Funded status of the plans — end of year	(214)	(160.9)
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	0	0
Unfunded liabilities — included in other noncurrent liabilities	(214)	(160.9)
Net amount recognized	(214)	(160.9)
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
Prior service credit	(0.6)	(0.6)
Net actuarial loss	31.4	22.5
Total	30.8	21.9
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	1.2	1.6
Net actuarial loss	181	138.4
Total	182.2	140
Other Postretirement Benefits
Change in benefit obligations:
Benefit obligations — beginning of year	25.4	21.3
Service cost	0.7	0.7	0.5
Interest cost	0.9	0.8	0.9
Actuarial loss (gain)	6.6	(2.7)
Plan amendments	(1.5)	0
Curtailment	(0.3)	0
Totalgaz acquisition	0	6.8
Foreign currency	0	(0.7)
Benefits paid	(0.9)	(0.8)
Benefit obligations — end of year	30.9	25.4	21.3
Change in plan assets:
Fair value of plan assets — beginning of year	12.5	12.8
Actual gain (loss) on plan assets	1.3	(0.1)
Foreign currency	0	0
Employer contributions	0.6	0.6
Totalgaz acquisition	0	0
Benefits paid	(0.7)	(0.8)
Fair value of plan assets — end of year	13.7	12.5	$ 12.8
Funded status of the plans — end of year	(17.2)	(12.9)
Assets (liabilities) recorded in the balance sheet:
Assets in excess of liabilities — included in other noncurrent assets	4.1	4
Unfunded liabilities — included in other noncurrent liabilities	(21.3)	(16.9)
Net amount recognized	(17.2)	(12.9)
Amounts recorded in UGI Corporation stockholders’ equity (pre-tax):
Prior service credit	(1.5)	(0.1)
Net actuarial loss	3.8	0.7
Total	2.3	0.6
Amounts recorded in regulatory assets and liabilities (pre-tax):
Prior service cost (credit)	(2.2)	(2.9)
Net actuarial loss	2.4	2.3
Total	$ 0.2	$ (0.6)

Employee Retirement Plans (Deta

Employee Retirement Plans (Details) - USD ($)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Defined Benefit Plan Disclosure
Amortization of net actuarial losses	$ 17,000,000
Amortization of prior service credits	$ 500,000
Percentage point change in assumed health care cost trend rate	1.00%
Projected benefit obligations of unfunded and non qualified supplemental executive retirement plans	$ 47,400,000	$ 40,100,000
Pre-tax cost to sponsor unfunded and non-qualified supplemental executive retirement plans	2,600,000	2,300,000	$ 2,600,000
Amounts recorded in UGI's stockholders include pre-tax losses representing unrecognized actuarial losses	(13,000,000)	$ (10,100,000)
Amount of expected amortization of pre-tax actuarial losses into retiree benefit cost	$ 1,200,000
Percentage of aggregate employer securities holdings to not to exceed fair value assets	10.00%
Percentage of common stock represented pension plan assets	8.00%	10.10%
Costs of benefits under savings plans	$ 14,300,000	$ 15,200,000	14,700,000
Supplemental Defined Contribution Executive Retirement Plans
Defined Benefit Plan Disclosure
Total fair values of grantor trust investment assets	4,600,000	4,200,000
U.S Pension Plans
Defined Benefit Plan Disclosure
ABO for the Pension Plans	601,300,000	523,700,000
Contribution made to Pension Plan	9,900,000	11,100,000	19,200,000
Fair value of Pension and Other Postretirement Benefit contributions	463,400,000	430,800,000
Supplemental Employee Retirement Plans
Defined Benefit Plan Disclosure
Pension and Other Postretirement Benefit contributions	400,000	0	$ 300,000
Supplemental Employee Retirement Plans | Other Assets
Defined Benefit Plan Disclosure
Fair value of Pension and Other Postretirement Benefit contributions	$ 28,400,000	$ 26,100,000

Employee Retirement Plans - Act

Employee Retirement Plans - Actuarial Assumptions for Domestic Plans (Details)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Benefit
Weighted-average assumption:
Discount rate - benefit obligations	3.80%	4.60%	4.60%
Discount rate - benefit cost	4.60%	4.60%	5.20%
Expected return on plan assets	7.55%	7.75%	7.75%
Rate of increase in salary levels	3.25%	3.25%	3.25%
Other Postretirement Benefits
Weighted-average assumption:
Discount rate - benefit obligations	3.80%	4.70%	4.60%
Discount rate - benefit cost	4.70%	4.60%
Expected return on plan assets	5.00%	5.00%	5.00%
Rate of increase in salary levels	3.25%	3.25%	3.25%
Other Postretirement Benefits | Minimum
Weighted-average assumption:
Discount rate - benefit cost			5.10%
Other Postretirement Benefits | Maximum
Weighted-average assumption:
Discount rate - benefit cost			5.40%

Employee Retirement Plans - Net

Employee Retirement Plans - Net Periodic Pension Expense and Other Postretirement Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Pension Benefit
Defined Benefit Plan Disclosure
Service cost	$ 10.1	$ 10	$ 9.4
Interest cost	26.8	25.5	26.1
Expected return on assets	(32.4)	(32.2)	(29.7)
Curtailment gain	(1.2)	(0.8)	0
Amortization of:
Prior service cost (benefit)	0.3	0.3	0.3
Actuarial loss	10.9	10	7.7
Net benefit cost	14.5	12.8	13.8
Change in associated regulatory liabilities	0	0	0
Net benefit cost after change in regulatory liabilities	14.5	12.8	13.8
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Service cost	0.7	0.7	0.5
Interest cost	0.9	0.8	0.9
Expected return on assets	(0.6)	(0.6)	(0.6)
Curtailment gain	0	0	0
Amortization of:
Prior service cost (benefit)	(0.6)	(0.5)	(0.5)
Actuarial loss	0	0.1	0
Net benefit cost	0.4	0.5	0.3
Change in associated regulatory liabilities	1	3.7	3.7
Net benefit cost after change in regulatory liabilities	$ 1.4	$ 4.2	$ 4

Employee Retirement Plans - Exp

Employee Retirement Plans - Expected Payments for Pension Benefits and Other Postretirement Welfare Benefits (Details) $ in Millions	Sep. 30, 2016USD ($)
Pension Benefit
Defined Benefit Plan Disclosure
Fiscal 2,017	$ 28.7
Fiscal 2,018	28.7
Fiscal 2,019	30
Fiscal 2,020	36.3
Fiscal 2,021	39.5
Fiscal 2022-2026	189.1
Other Postretirement Benefits
Defined Benefit Plan Disclosure
Fiscal 2,017	1.1
Fiscal 2,018	1.1
Fiscal 2,019	1.1
Fiscal 2,020	1.1
Fiscal 2,021	1.1
Fiscal 2022-2026	$ 5.5

Employee Retirement Plans - Sch

Employee Retirement Plans - Schedule of Health Care Cost Trend Rates (Details)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure
Fiscal year that the rate reaches the ultimate trend rate	2,026	2,026
Maximum
Defined Benefit Plan Disclosure
Health care cost trend rate assumed for next year	7.25%	7.50%
Minimum
Defined Benefit Plan Disclosure
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	5.00%	5.00%

Employee Retirement Plans - Pen

Employee Retirement Plans - Pension Plans (Details)	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Pension Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	100.00%	100.00%
Target Asset Allocation	100.00%
Pension Benefit | Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	64.30%	66.40%
Target Asset Allocation	65.00%
Permitted Range - Minimum	60.00%
Permitted Range - Maximum	70.00%
Pension Benefit | Domestic equity investments:
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	54.10%	56.20%
Target Asset Allocation	52.50%
Permitted Range - Minimum	40.00%
Permitted Range - Maximum	65.00%
Pension Benefit | International Index Equity Mutual Funds
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	10.20%	10.20%
Target Asset Allocation	12.50%
Permitted Range - Minimum	7.50%
Permitted Range - Maximum	17.50%
Pension Benefit | Fixed Income Funds and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	35.70%	33.60%
Target Asset Allocation	35.00%
Permitted Range - Minimum	30.00%
Permitted Range - Maximum	40.00%
VEBA Trust
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	100.00%	100.00%
Target Asset Allocation	100.00%
VEBA Trust | Domestic equity investments:
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	69.90%	67.40%
Target Asset Allocation	65.00%
Permitted Range - Minimum	60.00%
Permitted Range - Maximum	70.00%
VEBA Trust | Fixed Income Funds and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans
Actual Pension Plan	30.10%	32.60%
Target Asset Allocation	35.00%
Permitted Range - Minimum	30.00%
Permitted Range - Maximum	40.00%

Employee Retirement Plans - Fai

Employee Retirement Plans - Fair Value of U.S. Pension Plan and VEBA Trust Assets (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
U.S Pension Plans
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 463.4	$ 430.8
U.S Pension Plans | Domestic equity investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	250.5	242
U.S Pension Plans | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	158.9	147.3
U.S Pension Plans | Small and Midcap Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	43.2	40.6
U.S Pension Plans | Smallcap Common Stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	11.4	10.7
U.S Pension Plans | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	37	43.4
U.S Pension Plans | International Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	47.3	43.9
U.S Pension Plans | Fixed income investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	165.6	144.9
U.S Pension Plans | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	147.8	140.8
U.S Pension Plans | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	17.8	4.1
VEBA Trust
Defined Benefit Plan Disclosure
Fair value of plan assets	13.7	12.5
VEBA Trust | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	9.6	8.4
VEBA Trust | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	4	3.8
VEBA Trust | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0.1	0.3
Level 1 | U.S Pension Plans
Defined Benefit Plan Disclosure
Fair value of plan assets	445.6	426.7
Level 1 | U.S Pension Plans | Domestic equity investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	250.5	242
Level 1 | U.S Pension Plans | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	158.9	147.3
Level 1 | U.S Pension Plans | Small and Midcap Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	43.2	40.6
Level 1 | U.S Pension Plans | Smallcap Common Stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	11.4	10.7
Level 1 | U.S Pension Plans | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	37	43.4
Level 1 | U.S Pension Plans | International Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	47.3	43.9
Level 1 | U.S Pension Plans | Fixed income investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	147.8	140.8
Level 1 | U.S Pension Plans | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	147.8	140.8
Level 1 | U.S Pension Plans | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 1 | VEBA Trust
Defined Benefit Plan Disclosure
Fair value of plan assets	13.6	12.2
Level 1 | VEBA Trust | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	9.6	8.4
Level 1 | VEBA Trust | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	4	3.8
Level 1 | VEBA Trust | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans
Defined Benefit Plan Disclosure
Fair value of plan assets	17.8	4.1
Level 2 | U.S Pension Plans | Domestic equity investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | Small and Midcap Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | Smallcap Common Stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | International Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | Fixed income investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	17.8	4.1
Level 2 | U.S Pension Plans | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | U.S Pension Plans | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	17.8	4.1
Level 2 | VEBA Trust
Defined Benefit Plan Disclosure
Fair value of plan assets	0.1	0.3
Level 2 | VEBA Trust | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | VEBA Trust | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 2 | VEBA Trust | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0.1	0.3
Level 3 | U.S Pension Plans
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | Domestic equity investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | Small and Midcap Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | Smallcap Common Stocks
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | UGI Corporation Common Stock
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | International Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | Fixed income investments:
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | U.S Pension Plans | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | VEBA Trust
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | VEBA Trust | S&P 500 Index Equity Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | VEBA Trust | Bond Index Mutual Funds
Defined Benefit Plan Disclosure
Fair value of plan assets	0	0
Level 3 | VEBA Trust | Cash Equivalents
Defined Benefit Plan Disclosure
Fair value of plan assets	$ 0	$ 0

Utility Regulatory Assets and80

Utility Regulatory Assets and Liabilities and Regulatory Matters - Regulatory Assets and Liabilities Associated with Utilities (Details) - USD ($) $ in Millions		Sep. 30, 2016	Sep. 30, 2015
Regulatory Assets and Liabilities
Regulatory assets		$ 395.1	$ 304.2
Regulatory liabilities	[1]	55.6	71
Postretirement Benefit Overcollections
Regulatory Assets and Liabilities
Regulatory liabilities	[1]	17.5	20
Deferred Fuel and Power Refunds
Regulatory Assets and Liabilities
Regulatory liabilities	[1]	22.3	36.6
State Income Tax Benefits — Distribution System Repairs
Regulatory Assets and Liabilities
Regulatory liabilities	[1]	15.1	13.3
Other
Regulatory Assets and Liabilities
Regulatory liabilities	[1]	0.7	1.1
Income Taxes Recoverable
Regulatory Assets and Liabilities
Regulatory assets		115.7	115.9
Underfunded Pension and Postretirement Plans
Regulatory Assets and Liabilities
Regulatory assets		183.1	140.8
Environmental Costs
Regulatory Assets and Liabilities
Regulatory assets	[2]	59.4	20
Removal Costs, Net
Regulatory Assets and Liabilities
Regulatory assets		27.9	21.2
Other
Regulatory Assets and Liabilities
Regulatory assets		$ 9	$ 6.3
[1]	Regulatory liabilities are recorded in other current and other noncurrent liabilities on the Consolidated Balance Sheets.
[2]	Balance at September 30, 2016, includes amounts associated with UGI Gas’ Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (see Note 15).

Utility Regulatory Assets and81

Utility Regulatory Assets and Liabilities and Regulatory Matters (Details) - USD ($) $ in Millions	Oct. 19, 2016	Oct. 14, 2016	Jun. 30, 2016	Apr. 01, 2016	Jan. 19, 2016	Apr. 01, 2015	Mar. 31, 2016	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2014	Sep. 30, 2015
Regulatory Assets and Liabilities
Associated increase to utility property, plant and equipment									$ 5,346.4		$ 5,075.6
UGI Utilities
Regulatory Assets and Liabilities
Capitalized project costs							$ 5.8	$ 5.8
Project costs expensed in prior periods								5.4
UGI Utilities | Pennsylvania Public Utility Commission
Regulatory Assets and Liabilities
Requested operating revenue increase					$ 58.6
Amount of operating revenue increase			$ 27
Maximum period since petition to file a general rate filing									5 years
DSIC, percent of amount billed to customers										0.00%
UGI Utilities | Pennsylvania Public Utility Commission | PNG
Regulatory Assets and Liabilities
DSIC, percent of amount billed to customers						0.00%
UGI Utilities | Pennsylvania Public Utility Commission | CPG
Regulatory Assets and Liabilities
DSIC, percent of amount billed to customers				0.00%
UGI Utilities | Information Technology
Regulatory Assets and Liabilities
Associated increase to utility property, plant and equipment							$ 2.7	2.7
Subsequent Event | UGI Utilities | Pennsylvania Public Utility Commission
Regulatory Assets and Liabilities
Approved operating revenue increase		$ 27
Minimum
Regulatory Assets and Liabilities
Average remaining depreciable lives of the associated property									1 year
Maximum
Regulatory Assets and Liabilities
Average remaining depreciable lives of the associated property									65 years
Maximum | UGI Utilities | Pennsylvania Public Utility Commission
Regulatory Assets and Liabilities
DSIC, percent of amount billed to customers							5.00%		5.00%
Maximum | UGI Utilities | Pennsylvania Public Utility Commission | PNG
Regulatory Assets and Liabilities
DSIC, percent of amount billed to customers							10.00%
Maximum | UGI Utilities | Pennsylvania Public Utility Commission | CPG
Regulatory Assets and Liabilities
DSIC, percent of amount billed to customers							10.00%
Maximum | Postretirement Benefit Overcollections | Subsequent Event
Regulatory Assets and Liabilities
Regulatory liability, period overcollections will be refunded to customers	10 years
Removal Costs, Net | Maximum
Regulatory Assets and Liabilities
Regulatory asset, amortization period									5 years
Gas Utility
Regulatory Assets and Liabilities
Fair value of unrealized gains (losses)									$ 4.3		$ (3.3)
Other Regulatory Assets | Minimum
Regulatory Assets and Liabilities
Regulatory asset, amortization period									1 year
Other Regulatory Assets | Maximum
Regulatory Assets and Liabilities
Regulatory asset, amortization period									20 years
Deferred Project Costs | UGI Utilities
Regulatory Assets and Liabilities
Associated increase to utility regulatory assets							$ 3.1	$ 3.1

Inventories - Schedule of Inven

Inventories - Schedule of Inventories (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Public Utilities, Inventory
Total inventories	$ 210.3	$ 239.9
Non-utility LPG and Natural Gas
Public Utilities, Inventory
Total inventories	129.8	140.7
Gas Utility Natural Gas
Public Utilities, Inventory
Total inventories	29.2	37.5
Materials, Supplies and Other
Public Utilities, Inventory
Total inventories	$ 51.3	$ 61.7

Inventories (Details)

Inventories (Details) - UGI Utilities $ in Millions, ft³ in Billions	12 Months Ended
	Sep. 30, 2016USD ($)storage_agreementft³	Sep. 30, 2015USD ($)ft³
Public Utilities, Inventory
Storage agreement term (in years)	3 years
Storage Contract Administrative Agreements
Public Utilities, Inventory
Number of storage agreements | storage_agreement	3
Volume of gas storage inventories released under SCAAs with non-affiliates (in cubic feet) | ft³	3.5	4
Carrying value of gas storage inventories released under SCAAs with non-affiliates | $	$ 7.6	$ 9.8

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Property, Plant and Equipment
Utilities	$ 2,998.9	$ 2,753.5
Non-utility	5,346.4	5,075.6
Total property, plant and equipment	8,345.3	7,829.1
Distribution
Property, Plant and Equipment
Utilities	2,634.2	2,458.1
Transmission
Property, Plant and Equipment
Utilities	93.5	90
General and Other, Including Work-in-Process
Property, Plant and Equipment
Utilities	271.2	205.4
Land
Property, Plant and Equipment
Non-utility	169.9	174.9
Building and Improvements
Property, Plant and Equipment
Non-utility	382.2	391.4
Transportation Equipment
Property, Plant and Equipment
Non-utility	301.7	327.9
Equipment, Primarily Cylinders and Tanks
Property, Plant and Equipment
Non-utility	3,421.5	3,268.1
Electric Generation
Property, Plant and Equipment
Non-utility	309.4	305.7
Pipeline and Related Assets
Property, Plant and Equipment
Non-utility	235.8	233.5
Other, Including Work-in-Process
Property, Plant and Equipment
Non-utility	$ 525.9	$ 374.1

Goodwill and Intangible Asset85

Goodwill and Intangible Assets - Changes in the Carrying Amount of Goodwill (Details) - USD ($) $ in Millions		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Goodwill
Goodwill - balance at beginning of period	[1]	$ 2,953.4	$ 2,833.4
Acquisitions		41.1	200
Dispositions		(1.6)	(1)
Purchase price adjustments		(4.5)
Foreign currency translation		0.6	(79)
Goodwill - balance at end of period		2,989	2,953.4	[1]
Operating Segments | AmeriGas Propane
Goodwill
Goodwill - balance at beginning of period	[1]	1,956	1,945.1
Acquisitions		24.2	10.9
Dispositions		0	0
Purchase price adjustments		(1.9)
Foreign currency translation		0	0
Goodwill - balance at end of period		1,978.3	1,956	[1]
Operating Segments | Gas Utility
Goodwill
Goodwill - balance at beginning of period	[1]	182.1	182.1
Acquisitions		0	0
Dispositions		0	0
Purchase price adjustments		0
Foreign currency translation		0	0
Goodwill - balance at end of period		182.1	182.1	[1]
Operating Segments | Energy Services
Goodwill
Goodwill - balance at beginning of period	[2]	11.6	12.6
Acquisitions	[2]	0	0
Dispositions	[2]	0	(1)
Purchase price adjustments	[2]	0
Foreign currency translation	[2]	0	0
Goodwill - balance at end of period	[2]	11.6	11.6
Operating Segments | UGI France
Goodwill
Goodwill - balance at beginning of period	[1]	721.4	601.2
Acquisitions		0	186.2
Dispositions		0	0
Purchase price adjustments		(2.4)
Foreign currency translation		4.2	(66)
Goodwill - balance at end of period		723.2	721.4	[1]
Operating Segments | Flaga & Other
Goodwill
Goodwill - balance at beginning of period	[1]	82.3	92.4
Acquisitions		16.9	2.9
Dispositions		(1.6)	0
Purchase price adjustments		(0.2)
Foreign currency translation		(3.6)	(13)
Goodwill - balance at end of period		$ 93.8	$ 82.3	[1]
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).
[2]	Prior year amounts were restated to reflect the current-year changes in the presentation of our Energy Services reportable segment (see Note 21).

Goodwill and Intangible Asset86

Goodwill and Intangible Assets - Components of Intangible Assets (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Customer relationships, noncompete agreements and other	$ 773.5	$ 761.1
Trademarks and tradenames (not subject to amortization)	131.6	131.4
Gross carrying amount	905.1	892.5
Accumulated amortization	(324.8)	(282.4)
Intangible assets, net	$ 580.3	$ 610.1

Goodwill and Intangible Asset87

Goodwill and Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense of intangible assets	$ 54.3	$ 52	$ 48.2
Expected aggregate amortization expense of intangible assets for the next five fiscal years:
Fiscal 2,017	48.6
Fiscal 2,018	47.1
Fiscal 2,019	45.4
Fiscal 2,020	44.1
Fiscal 2,021	$ 42.2

Series Preferred Stock (Details

Series Preferred Stock (Details) - shares	Sep. 30, 2016	Sep. 30, 2015
Preferred Stock, authorized (in shares)	10,000,000
Preferred Stock, shares outstanding (in shares)	0	0
UGI Utilities
Preferred Stock, authorized (in shares)	2,000,000
Preferred Stock, shares outstanding (in shares)	0	0

Common Stock and Equity-Based89

Common Stock and Equity-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		Jan. 30, 2014	Jan. 24, 2013	Sep. 30, 2016		Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award
Treasury stock acquired				$ 36.9		$ 44.9
Pre-tax equity-based compensation expense				23.8		29.2	$ 25.8
After tax equity-based compensation expense				15.4		18.9	16.6
Cash received from stock option exercises				27.3		16.2	22.2
Associated tax benefits				14.9		$ 5.8	$ 13
Unrecognized compensation cost associated with unvested unit awards				$ 5.3
Weighted-average period of recognition for unvested unit awards				1 year 11 months
UGI Stock Option Awards
Share-based Compensation Arrangement by Share-based Payment Award
Weighted-average fair value of stock option granted under stock plans (in dollars per share)				$ 4.87		$ 5.47	$ 4.97
Amerigas Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Unrecognized compensation cost associated with unvested unit awards				$ 1.8
Weighted-average period of recognition for unvested unit awards				1 year 6 months
UGI Unit awards outstanding (in shares)				210,549		192,583
Fair value of unit awards vested				$ 2		$ 2.6	$ 4.1
Liabilities associated with share based compensation				$ 3.5		$ 3.3
AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Expected term of Performance Unit awards				3 years
Expected volatility measurement period (in years)				3 years
UGI Units awarded (in shares)				52,495
Weighted average grant date fair value unit awards (in dollars per share)				$ 37.65
AmeriGas Performance Unit | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
AmeriGas Performance Unit | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
AmeriGas Partners Common Units
Share-based Compensation Arrangement by Share-based Payment Award
UGI Units awarded (in shares)				20,585
Weighted average grant date fair value unit awards (in dollars per share)				$ 38.65
UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Unrecognized compensation cost associated with unvested unit awards				$ 8.6
Weighted-average period of recognition for unvested unit awards				1 year 9 months 12 days
Award performance period				3 years
UGI Units awarded (in shares)				230,653		180,724	234,264
Weighted average grant date fair value unit awards (in dollars per share)				$ 33.04		$ 38.20	$ 31.38
UGI Unit awards outstanding (in shares)				999,083		1,136,251
Fair value of unit awards vested				$ 9.7		$ 15.3	$ 8.7
Liabilities associated with share based compensation				$ 18.5		$ 19.9
UGI Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
UGI Units awarded (in shares)				52,493	[1]	39,801	44,814
Weighted average grant date fair value unit awards (in dollars per share)	[1]			$ 34.39
UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Weighted-average fair value of stock option granted under stock plans (in dollars per share)				$ 32.64		$ 38.43	$ 32.32
Expected term of Performance Unit awards				3 years
Expected volatility measurement period (in years)				3 years
UGI Units awarded (in shares)				178,160
Weighted average grant date fair value unit awards (in dollars per share)				$ 32.64
Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
Issued on or after January 1, 2013 | UGI Performance Units and Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
Issued prior to January 1, 2013 | UGI Performance Units and Stock Units | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Issued on or after January 1, 2015 | AmeriGas Performance Unit | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Modification range for grants issued in January 2015				70.00%
Issued on or after January 1, 2015 | AmeriGas Performance Unit | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Modification range for grants issued in January 2015				130.00%
Grants Issued in January 2015 | AmeriGas Performance Unit | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
Grants Issued in January 2015 | AmeriGas Performance Unit | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Grants Issued in January 2016 | AmeriGas Performance Unit | Minimum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				0.00%
Grants Issued in January 2016 | AmeriGas Performance Unit | Maximum
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Total Unitholder Return at 25th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				25.00%
Total Unitholder Return at 25th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				25.00%
Total Unitholder Return at 40th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				70.00%
Total Unitholder Return at 40th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				70.00%
Total Unitholder Return at 40th Percentile | Issued prior to January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				50.00%
Total Unitholder Return at 50th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				100.00%
Total Unitholder Return at 50th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				100.00%
Total Unitholder Return at 50th Percentile | Issued prior to January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				100.00%
Total Unitholder Return at 60th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				125.00%
Total Unitholder Return at 75th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				162.50%
Total Unitholder Return at 90th Percentile | Issued on or after January 1, 2013 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Total Unitholder Return at 90th Percentile | Issued on or after January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Total Unitholder Return at 100th Percentile | Issued prior to January 1, 2013 | UGI Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				200.00%
Total Unitholder Return Highest of Propane MLP Group | Certain Grants Issued on or After January 1, 2014 | AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Percentage of target award to be granted				150.00%
2010 Propane Plan | Amerigas Performance Units and Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Expiration period				10 years
Common Stock awards granted (in shares)				2,800,000
Award performance period				3 years
2010 Propane Plan | AmeriGas Partners Common Units
Share-based Compensation Arrangement by Share-based Payment Award
Weighted-average fair value of stock option granted under stock plans (in dollars per share)				$ 36.61		$ 61	$ 43.34
UGI Units awarded (in shares)				73,080		80,336	86,458
Number of common unit awards available for future grant (in shares)				2,348,046
UGI Corporation Common Stock
Share-based Compensation Arrangement by Share-based Payment Award
Maximum number of shares authorized for repurchase (in shares)		15,000,000
Duration of stock repurchase program		4 years
Treasury stock acquired				$ 47.6		$ 34.1	$ 39.8
UGI Corporation Common Stock | 2013 Omnibus Incentive Compensation Plan (OICP)
Share-based Compensation Arrangement by Share-based Payment Award
Expiration period			10 years
Common Stock awards granted (in shares)			21,750,000
Number of common unit awards available for future grant (in shares)				13,042,345
UGI Corporation Common Stock | 2004 Omnibus Equity Compensation Plan (OECP)
Share-based Compensation Arrangement by Share-based Payment Award
Expiration period				10 years
Number of common unit awards available for future grant (in shares)				4,116
UGI Corporation Common Stock | Treasury Stock
Share-based Compensation Arrangement by Share-based Payment Award
Treasury stock acquired (in shares)				(1,250,000)		(1,000,000)	(1,227,654)
[1]	Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2015 and Fiscal 2014 were 39,801 and 44,814, respectively.

Common Stock and Equity-Based90

Common Stock and Equity-Based Compensation - Common Stock Share Activity (Details) - UGI Corporation Common Stock - shares	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Common Stock Share Activity
Beginning balance - shares issued (in shares)	173,806,991	173,770,641	173,675,691
Beginning balance - shares outstanding (in shares)	172,388,503	172,273,781	171,643,287
Employee and director plans - shares issued (in shares)	87,150	36,350	94,950
Employee and director plans - shares outstanding (in shares)	2,442,352	1,191,726	3,023,090
Repurchases of common stock - shares outstanding (in shares)	(1,250,000)	(1,000,000)	(1,227,654)
Reacquired common stock, employee and director plans - shares outstanding (in shares)	(620,406)	(77,004)	(1,164,942)
Ending balance - shares issued (in shares)	173,894,141	173,806,991	173,770,641
Ending balance - shares outstanding (in shares)	172,960,449	172,388,503	172,273,781
Treasury Stock
Common Stock Share Activity
Beginning balance - shares issued (in shares)	(1,418,488)	(1,496,860)	(2,032,404)
Employee and director plans - shares issued (in shares)	2,355,202	1,155,376	2,928,140
Repurchases of common stock - held in treasury (in shares)	(1,250,000)	(1,000,000)	(1,227,654)
Reacquired common stock, employee and director plans - held in treasury (in shares)	(620,406)	(77,004)	(1,164,942)
Ending balance - shares issued (in shares)	(933,692)	(1,418,488)	(1,496,860)

Common Stock and Equity-Based91

Common Stock and Equity-Based Compensation - Stock Option Awards (Details) - UGI Stock Option Awards - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2013
Shares
Shares under option - beginning balance (in shares)	9,255,377	8,957,290	10,193,952
Granted (in shares)	1,510,625	1,336,985	1,665,600
Canceled (in shares)	(84,213)	(85,365)	(86,707)
Exercised (in shares)	(2,193,338)	(953,533)	(2,815,555)
Shares under option - ending balance (in shares)	8,488,451	9,255,377	8,957,290	10,193,952
Weighted Average Option Price
Shares under option - beginning balance (in dollars per share)	$ 23.97	$ 21.44	$ 19.28
Granted (in dollars per share)	34.67	37.70	27.93
Canceled (in dollars per share)	34.13	30.45	22.76
Exercised (in dollars per share)	20.38	19.10	17.44
Shares under option - ending balance (in dollars per share)	$ 26.68	$ 23.97	$ 21.44	$ 19.28
Total Intrinsic Value
Shares under option - beginning balance	$ 104.5	$ 113.3	$ 69.6
Exercised	40.1	15.4	37.4
Shares under option - beginning balance	$ 157.6	$ 104.5	$ 113.3	$ 69.6
Weighted Average Contract Term
Weighted average contract term (in years)	6 years 7 months	6 years 7 months 18 days	7 years	6 years 9 months 18 days
Options Exercisable
Options exercisable (in shares)	5,522,370	6,050,946	5,073,347
Option exercisable (in dollars per share)	$ 22.94	$ 20.74	$ 19.45
Option exercisable	$ 123.2
Option exercisable (in years)	5 years 7 months
Options Not Exercisable
Options not exercisable (in shares)	2,966,081
Options not exercisable (in dollars per share)	$ 33.63
Options not exercisable	$ 34.4
Options not exercisable (in years)	8 years 2 months

Common Stock and Equity-Based92

Common Stock and Equity-Based Compensation - Additional Information Relating to Stock Options Outstanding and Exercisable (Details) - UGI Stock Option Awards	12 Months Ended
	Sep. 30, 2016$ / sharesshares
$20.00
Share-based Compensation Arrangement by Share-based Payment Award
Number of options (in shares) | shares	1,876,551
Weighted average remaining contractual life (in years)	4 years 1 month
Weighted average exercise price (in dollars per share)	$ 18.10
Number of options (in shares) | shares	1,876,551
Weighted average exercise price (in dollars per share)	$ 18.10
Range of exercise prices, lower limit (in dollars per share)	0
Range of exercise prices, upper limit (in dollars per share)	$ 20
$20.01 - $25.00
Share-based Compensation Arrangement by Share-based Payment Award
Number of options (in shares) | shares	2,209,352
Weighted average remaining contractual life (in years)	5 years 7 months
Weighted average exercise price (in dollars per share)	$ 21.58
Number of options (in shares) | shares	2,073,902
Weighted average exercise price (in dollars per share)	$ 21.56
Range of exercise prices, lower limit (in dollars per share)	20.01
Range of exercise prices, upper limit (in dollars per share)	$ 25
$25.01 - $30.00
Share-based Compensation Arrangement by Share-based Payment Award
Number of options (in shares) | shares	1,591,195
Weighted average remaining contractual life (in years)	7 years 1 month
Weighted average exercise price (in dollars per share)	$ 27.44
Number of options (in shares) | shares	1,033,454
Weighted average exercise price (in dollars per share)	$ 27.34
Range of exercise prices, lower limit (in dollars per share)	25.01
Range of exercise prices, upper limit (in dollars per share)	$ 30
$30.01 - $35.00
Share-based Compensation Arrangement by Share-based Payment Award
Number of options (in shares) | shares	1,453,584
Weighted average remaining contractual life (in years)	9 years 1 month
Weighted average exercise price (in dollars per share)	$ 33.65
Number of options (in shares) | shares	117,050
Weighted average exercise price (in dollars per share)	$ 32.90
Range of exercise prices, lower limit (in dollars per share)	30.01
Range of exercise prices, upper limit (in dollars per share)	$ 35
$35.00
Share-based Compensation Arrangement by Share-based Payment Award
Number of options (in shares) | shares	1,357,769
Weighted average remaining contractual life (in years)	8 years 5 months
Weighted average exercise price (in dollars per share)	$ 38.46
Number of options (in shares) | shares	421,413
Weighted average exercise price (in dollars per share)	$ 37.73
Range of exercise prices, lower limit (in dollars per share)	$ 35.01

Common Stock and Equity-Based93

Common Stock and Equity-Based Compensation - Assumptions Used for Valuing Option Grants (Details) - UGI Stock Option Awards	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
Expected life of option	5 years 9 months	5 years 9 months	5 years 9 months
Weighted average volatility	19.50%	19.50%	24.30%
Weighted average dividend yield	2.60%	2.50%	2.90%
Expected volatility	19.30%
Expected dividend yield	2.60%	2.50%
Minimum
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
Expected volatility		19.10%	23.70%
Expected dividend yield			2.70%
Risk-free rate	1.20%	1.50%	1.80%
Maximum
Weighted average assumptions used to determine the fair value of UGI Performance Unit awards and related compensation costs
Expected volatility		19.50%	24.40%
Expected dividend yield			2.90%
Risk-free rate	1.90%	1.80%	2.00%

Common Stock and Equity-Based94

Common Stock and Equity-Based Compensation - Weighted Average Assumptions Used to Determine the Fair Value of UGI Performance Unit Awards and Related Compensation Costs (Details) - UGI Performance Units	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award
Risk-free rate	1.30%	1.10%	0.80%
Expected life	3 years	3 years	3 years
Expected volatility	17.50%	15.90%	20.30%
Dividend yield	2.70%	2.30%	2.70%

Common Stock and Equity-Based95

Common Stock and Equity-Based Compensation - UGI Performance Unit Award Activity (Details) - $ / shares		12 Months Ended
		Sep. 30, 2016		Sep. 30, 2015	Sep. 30, 2014
UGI Performance Units and Stock Units
Number of UGI Units
Number of units - beginning balance (in shares)		1,136,251
Granted (in shares)		230,653		180,724	234,264
Number of units - ending balance (in shares)		999,083		1,136,251
Weighted Average Grant Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share)		$ 23.78
Granted (in dollars per share)		33.04		$ 38.20	$ 31.38
Weighted average grant date fair value - ending balance (in dollars per share)		$ 25.44		$ 23.78
UGI Performance Units
Number of UGI Units
Granted (in shares)		178,160
Forfeited (in shares)		(17,356)
Vested (in shares)		0
Awards paid (in shares)		(296,687)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share)		$ 32.64
Forfeited (in dollars per share)		34.62
Vested (in dollars per share)		0
Awards paid (in dollars per share)		$ 25.98
UGI Stock Units
Number of UGI Units
Granted (in shares)		52,493	[1]	39,801	44,814
Awards paid (in shares)		(53,778)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share)	[1]	$ 34.39
Awards paid (in dollars per share)		$ 16.86
Shares granted under stock awards (percentage)		70.00%
Vested | UGI Performance Units and Stock Units
Number of UGI Units
Number of units - beginning balance (in shares)		803,817
Number of units - ending balance (in shares)		672,075		803,817
Weighted Average Grant Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share)		$ 20.19
Weighted average grant date fair value - ending balance (in dollars per share)		$ 21.17		$ 20.19
Vested | UGI Performance Units
Number of UGI Units
Granted (in shares)		25,291
Forfeited (in shares)		0
Vested (in shares)		154,339
Awards paid (in shares)		(296,687)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share)		$ 32.77
Forfeited (in dollars per share)		0
Vested (in dollars per share)		28.66
Awards paid (in dollars per share)		$ 25.98
Vested | UGI Stock Units
Number of UGI Units
Granted (in shares)	[1]	39,093
Awards paid (in shares)		(53,778)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share)	[1]	$ 33.40
Awards paid (in dollars per share)		$ 16.86
Non-Vested | UGI Performance Units and Stock Units
Number of UGI Units
Number of units - beginning balance (in shares)		332,434
Number of units - ending balance (in shares)		327,008		332,434
Weighted Average Grant Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share)		$ 32.28
Weighted average grant date fair value - ending balance (in dollars per share)		$ 34.21		$ 32.28
Non-Vested | UGI Performance Units
Number of UGI Units
Granted (in shares)		152,869
Forfeited (in shares)		(17,356)
Vested (in shares)		154,339
Awards paid (in shares)		0
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share)		$ 32.62
Forfeited (in dollars per share)		34.62
Vested (in dollars per share)		28.66
Awards paid (in dollars per share)		$ 0
Non-Vested | UGI Stock Units
Number of UGI Units
Granted (in shares)	[1]	13,400
Awards paid (in shares)		0
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share)	[1]	$ 37.29
Awards paid (in dollars per share)		$ 0
[1]	Generally, shares granted under UGI Stock Unit awards are paid approximately 70% in shares. UGI Stock Unit awards granted in Fiscal 2015 and Fiscal 2014 were 39,801 and 44,814, respectively.

Common Stock and Equity-Based96

Common Stock and Equity-Based Compensation - Schedule of Payment for UGI Performance Unit and UGI Stock Unit Awards in Shares and Cash (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
UGI Performance Units
Share-based Compensation Arrangement by Share-based Payment Award
Number of original awards granted (in shares)	308,362	294,300	331,038
Fiscal year granted	2,013	2,012	2,011
Payment of awards:
Shares of UGI Common Stock issued, net of shares withheld for taxes (in shares)	209,592	188,418	174,168
Cash paid	$ 13.9	$ 13.3	$ 3.1
UGI Stock Units
Share-based Compensation Arrangement by Share-based Payment Award
Number of original awards granted (in shares)	51,037	67,419	34,639
Payment of awards:
Shares of UGI Common Stock issued, net of shares withheld for taxes (in shares)	39,422	44,034	22,604
Cash paid	$ 0.7	$ 0.8	$ 0.4

Common Stock and Equity-Based97

Common Stock and Equity-Based Compensation - Weighted Average Assumption Used to Determine the Fair Value of AmeriGas Performance Unit Awards and Related Compensation Costs (Details) - AmeriGas Performance Unit	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award
Risk-free rate	1.30%	0.90%	0.80%
Expected life	3 years	3 years	3 years
Expected volatility	20.60%	19.20%	21.10%
Dividend yield	10.70%	6.80%	7.50%

Common Stock and Equity-Based98

Common Stock and Equity-Based Compensation - AmeriGas Common Unit Based Award Activity (Details)	12 Months Ended
	Sep. 30, 2016$ / sharesshares
Amerigas Performance Units and Stock Units
Number of AmeriGas Partners Common Units Subject to Award
Number of units - beginning balance (in shares) | shares	192,583
Number of units - ending balance (in shares) | shares	210,549
Weighted Average Grant Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share) | $ / shares	$ 49.70
Weighted average grant date fair value - ending balance (in dollars per share) | $ / shares	$ 47.24
AmeriGas Performance Unit
Number of AmeriGas Partners Common Units Subject to Award
Granted (in shares) | shares	52,495
Forfeited (in shares) | shares	(4,994)
Vested (in shares) | shares	0
Awards paid (in shares) | shares	(34,616)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share) | $ / shares	$ 37.65
Forfeited (in dollars per share) | $ / shares	54
Vested (in dollars per share) | $ / shares	0
Awards paid (in dollars per share) | $ / shares	$ 42.44
AmeriGas Partners Common Units
Number of AmeriGas Partners Common Units Subject to Award
Granted (in shares) | shares	20,585
Forfeited (in shares) | shares	(800)
Vested (in shares) | shares	0
Awards paid (in shares) | shares	(14,704)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share) | $ / shares	$ 38.65
Forfeited (in dollars per share) | $ / shares	42.33
Vested (in dollars per share) | $ / shares	0
Awards paid (in dollars per share) | $ / shares	$ 49.94
Vested | Amerigas Performance Units and Stock Units
Number of AmeriGas Partners Common Units Subject to Award
Number of units - beginning balance (in shares) | shares	46,900
Number of units - ending balance (in shares) | shares	55,622
Weighted Average Grant Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share) | $ / shares	$ 44.97
Weighted average grant date fair value - ending balance (in dollars per share) | $ / shares	$ 45.67
Vested | AmeriGas Performance Unit
Number of AmeriGas Partners Common Units Subject to Award
Granted (in shares) | shares	1,267
Forfeited (in shares) | shares	0
Vested (in shares) | shares	30,050
Awards paid (in shares) | shares	(34,616)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share) | $ / shares	$ 37.84
Forfeited (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	43.65
Awards paid (in dollars per share) | $ / shares	$ 42.44
Vested | AmeriGas Partners Common Units
Number of AmeriGas Partners Common Units Subject to Award
Granted (in shares) | shares	12,785
Forfeited (in shares) | shares	0
Vested (in shares) | shares	13,940
Awards paid (in shares) | shares	(14,704)
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share) | $ / shares	$ 36.69
Forfeited (in dollars per share) | $ / shares	0
Vested (in dollars per share) | $ / shares	49.94
Awards paid (in dollars per share) | $ / shares	$ 49.94
Non-Vested | Amerigas Performance Units and Stock Units
Number of AmeriGas Partners Common Units Subject to Award
Number of units - beginning balance (in shares) | shares	145,683
Number of units - ending balance (in shares) | shares	154,927
Weighted Average Grant Date Fair Value (per Unit)
Weighted average grant date fair value - beginning balance (in dollars per share) | $ / shares	$ 51.22
Weighted average grant date fair value - ending balance (in dollars per share) | $ / shares	$ 47.80
Non-Vested | AmeriGas Performance Unit
Number of AmeriGas Partners Common Units Subject to Award
Granted (in shares) | shares	51,228
Forfeited (in shares) | shares	(4,994)
Vested (in shares) | shares	30,050
Awards paid (in shares) | shares	0
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share) | $ / shares	$ 37.65
Forfeited (in dollars per share) | $ / shares	54
Vested (in dollars per share) | $ / shares	43.65
Awards paid (in dollars per share) | $ / shares	$ 0
Non-Vested | AmeriGas Partners Common Units
Number of AmeriGas Partners Common Units Subject to Award
Granted (in shares) | shares	7,800
Forfeited (in shares) | shares	(800)
Vested (in shares) | shares	13,940
Awards paid (in shares) | shares	0
Weighted Average Grant Date Fair Value (per Unit)
Granted (in dollars per share) | $ / shares	$ 41.85
Forfeited (in dollars per share) | $ / shares	42.33
Vested (in dollars per share) | $ / shares	49.94
Awards paid (in dollars per share) | $ / shares	$ 0

Common Stock and Equity-Based99

Common Stock and Equity-Based Compensation - AmeriGas Common Unit Based Awards in Common Units and Cash (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
AmeriGas Performance Unit
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Units subject to original awards granted (in shares)	44,800	55,750	41,251
Fiscal year granted	2,013	2,012	2,011
Payment of awards:
AmeriGas Partners Common Units issued, net of units withheld for taxes (in shares)	23,017	0	0
Cash paid	$ 1.7	$ 0	$ 0
AmeriGas Partners Common Units
Share-based Compensation Arrangement by Share-based Payment Award
Number of Common Units subject to original awards granted (in shares)	20,336	42,532	72,023
Payment of awards:
AmeriGas Partners Common Units issued, net of units withheld for taxes (in shares)	9,272	21,509	40,842
Cash paid	$ 0.4	$ 0.8	$ 1.4

Partnership Distributions (Deta

Partnership Distributions (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Distribution Made to Limited Partner
Partnership distributions to partners (days following quarter end)	45 days
Pre-Incentive distribution of the available cash to Limited Partners	98.00%
Pre-Incentive distribution of available cash to General Partners	2.00%
General Partner Interest in AmeriGas partners	1.00%
General Partner Interest in AmeriGas OLP	1.01%
First target distribution (in dollars per share)	$ 0.055
Threshold for increased distribution to General Partner (in dollars per share)	$ 0.605
General Partners distribution based on ownership interest	$ 47.4	$ 39.3	$ 32.4
Incentive distributions received by the General Partner	$ 38.2	$ 30.4	$ 23.9
Minimum
Distribution Made to Limited Partner
Quarterly distribution (in dollars per share)	$ 0.55
Available cash for per common unit (in dollars per share)	$ 0.605	$ 0.605	$ 0.605

Commitments and Contingencie101

Commitments and Contingencies (Details)	1 Months Ended		6 Months Ended	12 Months Ended
	Sep. 30, 2016USD ($)	Jan. 31, 2015USD ($)	Oct. 31, 2014lawsuit	Sep. 30, 2016USD ($)lb	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2016subsidiary
Commitments and Contingencies
Aggregate rental expense for leases				$ 102,000,000	$ 86,100,000	$ 79,700,000
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA	$ 11,300,000			$ 11,300,000	$ 13,800,000
Amount awarded		$ 18,000,000
Adjustment to litigation accrual	15,000,000
Class action lawsuits (more than) | lawsuit			35
Amount of propane in cylinders being sold | lb				17
Reduced amount of propane in cylinders being sold | lb				15
PNG MGP
Commitments and Contingencies
Loss contingency, settlement agreement, terms				2 years
Environmental Issue | UGI Gas MGP Properties
Commitments and Contingencies
Expected environmental expenditures cap during calendar year				$ 2,500,000
Environmental Issue | CPG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year				1,800,000
Environmental Issue | PNG MGP
Commitments and Contingencies
Environmental expenditures cap during calendar year				$ 1,100,000
Maximum | Gas Utility
Commitments and Contingencies
Term of contracts				16 months
Maximum | Midstream and Marketing
Commitments and Contingencies
Term of contracts				2 years
Maximum | Partnership
Commitments and Contingencies
Term of contracts				3 years
Maximum | UGI International
Commitments and Contingencies
Term of contracts				3 years
The Partnership and UGI International | Minimum
Commitments and Contingencies
Contract terms subject to annual price and quantity adjustments (in years)				1 year
The Partnership and UGI International | Maximum
Commitments and Contingencies
Contract terms subject to annual price and quantity adjustments (in years)				3 years
UGI Utilities | UGI Gas-COA
Commitments and Contingencies
Accrued liabilities for environmental investigation and remediation costs related to CPG-COA and PNG-COA	$ 43,700,000			$ 43,700,000
UGI Utilities | PNG and CPG
Commitments and Contingencies
Number of subsidiaries acquired with similar histories | subsidiary							2

Commitments and Contingencies -

Commitments and Contingencies - Minimum Future Payments Under Operating Leases (Details) $ in Millions	Sep. 30, 2016USD ($)
Commitments and Contingencies
2,017	$ 80.1
2,018	69
2,019	59.5
2,020	51.3
2,021	40.7
After 2,021	112.1
AmeriGas Propane
Commitments and Contingencies
2,017	60.6
2,018	53.2
2,019	48.4
2,020	44.3
2,021	37
After 2,021	103.8
UGI Utilities
Commitments and Contingencies
2,017	6
2,018	5
2,019	3
2,020	1.3
2,021	0.6
After 2,021	0.2
UGI International
Commitments and Contingencies
2,017	11.4
2,018	8.8
2,019	6.4
2,020	4.2
2,021	2.8
After 2,021	8
Other
Commitments and Contingencies
2,017	2.1
2,018	2
2,019	1.7
2,020	1.5
2,021	0.3
After 2,021	$ 0.1

Commitments and Contingencie103

Commitments and Contingencies - Contractual Obligations Under Supply Storage and Service Contracts (Details) $ in Millions	Sep. 30, 2016USD ($)
Recorded Unconditional Purchase Obligation
2,017	$ 362.2
2,018	151.5
2,019	84.8
2,020	38.8
2,021	35
After 2,021	116
UGI Utilities Supply, Storage and Transportation Contracts
Recorded Unconditional Purchase Obligation
2,017	115.1
2,018	71.1
2,019	50.8
2,020	36.5
2,021	35
After 2,021	116
Midstream & Marketing Supply Contracts
Recorded Unconditional Purchase Obligation
2,017	168.4
2,018	80.4
2,019	34
2,020	2.3
2,021	0
After 2,021	0
UGI International Supply Contracts
Recorded Unconditional Purchase Obligation
2,017	78.7
2,018	0
2,019	0
2,020	0
2,021	0
After 2,021	$ 0

Fair Value Measurement - Financ

Fair Value Measurement - Financial Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Millions		Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		$ 72.7	$ 58.5
Derivative financial instruments, liabilities		(105.4)	(179.9)
Recurring Basis
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	[1]	33	30.3
Recurring Basis | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	[1]	33	30.3
Recurring Basis | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	[1]	0	0
Recurring Basis | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Non-qualified supplemental postretirement grantor trust investments	[1]	0	0
Recurring Basis | Commodity Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		54.9	29
Derivative financial instruments, liabilities		(98.6)	(169)
Recurring Basis | Commodity Contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		28.9	17.4
Derivative financial instruments, liabilities		(76.8)	(70)
Recurring Basis | Commodity Contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		26	11.6
Derivative financial instruments, liabilities		(21.8)	(99)
Recurring Basis | Commodity Contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		0	0
Derivative financial instruments, liabilities		0	0
Recurring Basis | Foreign Currency Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		17.8	29.1
Derivative financial instruments, liabilities		(2.4)	(0.1)
Recurring Basis | Foreign Currency Contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		0	0
Derivative financial instruments, liabilities		0	0
Recurring Basis | Foreign Currency Contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		17.8	29.1
Derivative financial instruments, liabilities		(2.4)	(0.1)
Recurring Basis | Foreign Currency Contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		0	0
Derivative financial instruments, liabilities		0	0
Recurring Basis | Interest Rate Contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		(3.9)	(10.8)
Recurring Basis | Interest Rate Contracts | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		0	0
Recurring Basis | Interest Rate Contracts | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		(3.9)	(10.8)
Recurring Basis | Interest Rate Contracts | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		0	0
Recurring Basis | Cross-currency Swaps
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			0.4
Derivative financial instruments, liabilities		(0.5)
Recurring Basis | Cross-currency Swaps | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			0
Derivative financial instruments, liabilities		0
Recurring Basis | Cross-currency Swaps | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			0.4
Derivative financial instruments, liabilities		(0.5)
Recurring Basis | Cross-currency Swaps | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets			$ 0
Derivative financial instruments, liabilities		$ 0
[1]	)Consists primarily of mutual fund investments held in grantor trusts associated with non-qualified supplemental retirement plans (see Note 7

Fair Value Measurement (Details

Fair Value Measurement (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Carrying amount of long-term debt	$ 3,832.3	$ 3,699.8
Estimated fair value long-term debt	$ 4,052.3	$ 3,803.1

Derivative Instruments and H106

Derivative Instruments and Hedging Activities (Details) € in Millions, $ in Millions	Mar. 31, 2016USD ($)	Mar. 31, 2016EUR (€)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2016EUR (€)	Sep. 30, 2016USD ($)	Sep. 30, 2015EUR (€)	Sep. 30, 2015USD ($)
Derivative
Restricted Cash and Cash Equivalents, Current							$ 15.6		$ 69.3
Settlement of UGI Utilities interest rate agreements			$ 36	$ 0	$ 0
Amount of net losses associated with interest rate hedges to be reclassified with interest rate hedges during the next 12 months							(3.4)
Amount of net losses associated with currency rate risk to be reclassified into earnings during the next 12 months							11.5
Restricted cash in brokerage accounts							15.6		54.9
Amounts of derivative losses representing ineffectiveness			$ 5.5
UGI France
Derivative
Derivative interest rate floor		0.00%
Interest Rate Swap
Derivative
Notional amount | €						€ 645.8		€ 645.8
Interest Rate Swap | Interest Expense
Derivative
Loss on interest rate swaps				$ 9
Interest Rate Swap | UGI France
Derivative
Payment to interest rate swap counterparties | €		€ 7.7
Interest Rate Swap | UGI France | Term Loan
Derivative
Notional amount | €		€ 600						€ 600
Interest Rate Protection Agreements
Derivative
Notional amount							$ 0		$ 250
Interest Rate Protection Agreements | UGI Utilities
Derivative
Settlement of UGI Utilities interest rate agreements	$ 36
EURIBOR | Interest Rate Swap | UGI France
Derivative
Underlying fixed interest rate (percentage)		0.18%

Derivative Instruments and H107

Derivative Instruments and Hedging Activities - Schedule of Notional Amounts (Details) € in Millions, kWh in Millions, gal in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Sep. 30, 2016EUR (€)kWhMMBTUgal	Sep. 30, 2015EUR (€)kWhMMBTUgal	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)
Commodity Contracts | Propane
Derivative
Notional amount (in gallons) | gal	396.9	516.3
Commodity Contracts | Electricity | Long
Derivative
Notional amount (energy measure)	761.2	474.3
Commodity Contracts | Electricity | Short
Derivative
Notional amount (energy measure)	264.6	297.9
Natural Gas Futures, Forward and Pipeline Contracts | Natural Gas
Derivative
Notional amount (energy measure) | MMBTU	71.1	110.2
Natural Gas Basis Swap Contracts | Natural Gas
Derivative
Notional amount (energy measure) | MMBTU	118.3	75.7
Natural Gas Storage and Propane Storage NYMEX Contracts | Propane
Derivative
Notional amount (in gallons) | gal	0	2
Natural Gas Storage and Propane Storage NYMEX Contracts | Natural Gas
Derivative
Notional amount (energy measure) | MMBTU	1.9	1.9
FTRs & NYISO Capacity Contracts | Electricity
Derivative
Notional amount (energy measure)	0	82
Interest Rate Swap
Derivative
Notional amount | €	€ 645.8	€ 645.8
Interest Rate Protection Agreements
Derivative
Notional amount | $			$ 0	$ 250
Foreign Currency Contracts
Derivative
Notional amount | $			314.3	227.9
Cross Currency Contracts
Derivative
Notional amount | $			$ 59.1	$ 59.1
Regulated Utility Operations | Commodity Contracts | Natural Gas
Derivative
Notional amount (energy measure) | MMBTU	18.4	18.9
Regulated Utility Operations | Commodity Contracts | Electricity
Derivative
Notional amount (energy measure)	0	136
Regulated Utility Operations | FTRs & NYISO Capacity Contracts | Electricity
Derivative
Notional amount (energy measure)	58.3	277.1

Derivative Instruments and H108

Derivative Instruments and Hedging Activities - Schedule of Derivative Assets, Liabilities and the Effects of Offsetting (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015
Derivative assets:
Derivative assets, gross	$ 72.7	$ 58.5
Gross amounts offset in the balance sheet	(35)	(18.9)
Cash collateral received	(0.3)	0
Total derivative assets - net	37.4	39.6
Derivative liabilities:
Derivative liabilities, gross	(105.4)	(179.9)
Gross amounts offset in the balance sheet	35	18.9
Cash collateral pledged	0	8
Total derivative liabilities - net	(70.4)	(153)
Commodity Contract Subject to PGC and DS Mechanisms
Derivative assets:
Derivative assets, gross	4.5	1.3
Derivative liabilities:
Derivative liabilities, gross	(0.5)	(5.6)
Designated as Hedging Instruments
Derivative assets:
Derivative assets, gross	17.8	29.5
Derivative liabilities:
Derivative liabilities, gross	(6.8)	(10.9)
Designated as Hedging Instruments | Foreign Currency Contracts
Derivative assets:
Derivative assets, gross	17.8	29.1
Derivative liabilities:
Derivative liabilities, gross	(2.4)	(0.1)
Designated as Hedging Instruments | Cross Currency Contracts
Derivative assets:
Derivative assets, gross	0	0.4
Derivative liabilities:
Derivative liabilities, gross	(0.5)	0
Designated as Hedging Instruments | Interest Rate Contracts
Derivative liabilities:
Derivative liabilities, gross	(3.9)	(10.8)
Not Designated as Hedging Instruments | Commodity Contracts
Derivative assets:
Derivative assets, gross	50.4	27.7
Derivative liabilities:
Derivative liabilities, gross	$ (98.1)	$ (163.4)

Derivative Instruments and H109

Derivative Instruments and Hedging Activities - Effects of Derivative Instruments on Condensed Consolidated Statements of Income and Changes in AOCI and Noncontrolling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Designated as Hedging Instruments | Cash Flow Hedges
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests	$ (28.8)	$ 24.8	$ 66.1
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income	13.1	(4.4)	47.3
Designated as Hedging Instruments | Cash Flow Hedges | Commodity Contracts
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests	0	0	50.8
Designated as Hedging Instruments | Cash Flow Hedges | Commodity Contracts | Cost of Sales
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income	0	(2.2)	67
Designated as Hedging Instruments | Cash Flow Hedges | Foreign Currency Contracts
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests	3.6	26	15.3
Designated as Hedging Instruments | Cash Flow Hedges | Foreign Currency Contracts | Cost of Sales
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income	17.2	9.7	(3.7)
Designated as Hedging Instruments | Cash Flow Hedges | Cross Currency Contracts
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests	0.1	5.4	3.1
Designated as Hedging Instruments | Cash Flow Hedges | Cross Currency Contracts | Interest Expense
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income	0.4	8.5	(0.1)
Designated as Hedging Instruments | Cash Flow Hedges | Interest Rate Contracts
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss recognized in accumulated other comprehensive income and noncontrolling interests	(32.5)	(6.6)	(3.1)
Designated as Hedging Instruments | Cash Flow Hedges | Interest Rate Contracts | Interest Expense / Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Derivative instruments gain loss reclassified from accumulated other comprehensive income and noncontrolling interest into income	(4.5)	(20.4)	(15.9)
Not Designated as Hedging Instruments
Derivative Instruments, Gain (Loss)
Gain or (loss) recognized in income	(67.3)	(376.3)	(36.3)
Not Designated as Hedging Instruments | Commodity Contracts | Cost of Sales
Derivative Instruments, Gain (Loss)
Gain or (loss) recognized in income	(65)	(375.8)	(36.3)
Not Designated as Hedging Instruments | Commodity Contracts | Revenues
Derivative Instruments, Gain (Loss)
Gain or (loss) recognized in income	(2.2)	0.3	0
Not Designated as Hedging Instruments | Commodity Contracts | Operating and Administrative Expenses / Other Operating Income, Net
Derivative Instruments, Gain (Loss)
Gain or (loss) recognized in income	$ (0.1)	$ (0.8)	$ 0

Accumulated Other Comprehens110

Accumulated Other Comprehensive Income - Schedule of Accumulated Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of year	$ 3,572.4	$ 3,663.2
Other comprehensive (loss) income before reclassification adjustments (after-tax)	(34.2)	(98.5)	$ 5.8
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	(10.5)	6.6	(45.6)
Reclassification adjustments tax expense	4.6	(3.6)	1.4
Reclassification adjustments (after-tax)	(5.9)	3	(44.2)
Other comprehensive income (loss)	(40.1)	(95.5)	(38.4)
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners		2.1	8.8
Other comprehensive income (loss) attributable to UGI	(40.1)	(93.4)	(29.6)
Balance, end of year	3,601.8	3,572.4	3,663.2
Postretirement Benefit Plans
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of year	(20.4)	(20.6)	(16.4)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	(10.9)	(1.2)	(5.2)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	2.6	2.2	1.6
Reclassification adjustments tax expense	(0.4)	(0.8)	(0.6)
Reclassification adjustments (after-tax)	2.2	1.4	1
Other comprehensive income (loss)		0.2	(4.2)
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners		0	0
Other comprehensive income (loss) attributable to UGI	(8.7)	0.2	(4.2)
Balance, end of year	(29.1)	(20.4)	(20.6)
Derivative Instruments
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of year	11.2	(9.3)	(26.9)
Other comprehensive (loss) income before reclassification adjustments (after-tax)	(16.5)	16.8	54
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	(13.1)	4.4	(47.2)
Reclassification adjustments tax expense	5	(2.8)	2
Reclassification adjustments (after-tax)	(8.1)	1.6	(45.2)
Other comprehensive income (loss)		18.4	8.8
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners		2.1	8.8
Other comprehensive income (loss) attributable to UGI	(24.6)	20.5	17.6
Balance, end of year	(13.4)	11.2	(9.3)
Foreign Currency
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of year	(105.4)	8.7	51.7
Other comprehensive (loss) income before reclassification adjustments (after-tax)	(6.8)	(114.1)	(43)
Amounts reclassified from AOCI and noncontrolling interests:
Reclassification adjustments (pre-tax)	0	0	0
Reclassification adjustments tax expense	0	0	0
Reclassification adjustments (after-tax)	0	0	0
Other comprehensive income (loss)		(114.1)	(43)
Add comprehensive loss attributable to noncontrolling interests, principally in AmeriGas Partners		0	0
Other comprehensive income (loss) attributable to UGI	(6.8)	(114.1)	(43)
Balance, end of year	(112.2)	(105.4)	8.7
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Balance, beginning of year	(114.6)	(21.2)	8.4
Amounts reclassified from AOCI and noncontrolling interests:
Balance, end of year	$ (154.7)	$ (114.6)	$ (21.2)

Other Operating Income, Net (De

Other Operating Income, Net (Details) - USD ($) $ in Millions	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Component of Operating Income [Abstract]
Interest and interest-related income	$ 0.2	$ 0.8	$ 3.6
Utility non-tariff service income	2.6	4.8	2.7
Finance charges	15.2	12.7	17.5
Gains on sales of fixed assets, net	3.3	11.1	5.4
Other, net	1.1	15	6.9
Total other operating income, net	$ 22.4	$ 44.4	$ 36.1

Quarterly Data (unaudited) - S

Quarterly Data (unaudited) - Schedule of Quarterly Data(Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended											12 Months Ended
	Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015		Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
Quarterly Financial Data [Abstract]
Revenues	$ 976.2	[1]	$ 1,130.8	[1]	$ 1,972.1	$ 1,606.6	$ 1,082.8	$ 1,148.1	[2]	$ 2,455.6	$ 2,004.6	$ 5,685.7	$ 6,691.1	[3]	$ 8,277.3	[3]
Operating income (loss)	(88.6)	[1]	155.7	[1]	615.4	305.5	(6.6)	56.1	[2]	702.1	83.3	988	834.9	[3]	1,005.6	[3]
Loss from equity investees	(0.1)	[1]	0	[1]	0	(0.1)	(0.1)	0	[2]	(0.1)	(1)	(0.2)	(1.2)	[3]	(0.1)	[3]
Loss on extinguishments of debt	(11.8)	[1]	(37.1)	[1]	0	0	0	0	[2]	0	0	(48.9)	0		0
Net income including noncontrolling interests	(115.7)	[1]	28.6	[1]	408	167.9	(52.5)	(15.9)	[2]	482.2	0.2	488.8	414		532.6
Net income (loss) attributable to UGI Corporation	$ (43.8)	[1]	$ 60.7	[1]	$ 233.2	$ 114.6	$ (9.2)	$ 9.6	[2]	$ 246.5	$ 34.1	$ 364.7	$ 281	[3]	$ 337.2	[3]
Earnings (loss) per common share attributable to UGI Corporation stockholders:
Basic (in dollars per share)	$ (0.25)	[1]	$ 0.35	[1]	$ 1.35	$ 0.66	$ (0.05)	$ 0.06	[2]	$ 1.42	$ 0.20	$ 2.11	$ 1.62		$ 1.95
Diluted (in dollars per share)	$ (0.25)	[1]	$ 0.34	[1]	$ 1.33	$ 0.65	$ (0.05)	$ 0.05	[2]	$ 1.40	$ 0.19	$ 2.08	$ 1.60		$ 1.92
Decrease in net income attributable to UGI Corporation	$ 1.8		$ 6.1					$ 4.6
Decrease in net income attribuable to UGI Corporation (in usd per share)	$ 0.01		$ 0.03					$ 0.03
[1]	Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5).
[2]	Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5)
[3]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Segment Information (Details)

Segment Information (Details)	12 Months Ended
	Sep. 30, 2016countystateCustomersegment
Segment Reporting [Abstract]
Number of reportable segments | segment	6
Number of states to which product sale with propane revenue | state	50
Segment Reporting Information
Number of counties	1
UGI Utilities
Segment Reporting Information
Number of counties	2
Customer Concentration Risk | Revenues, Consolidated
Segment Reporting Information
Number of customers | Customer	0

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting (Details) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Sep. 30, 2016		Jun. 30, 2016	[1]	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015		Jun. 30, 2015	[2]	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016		Sep. 30, 2015		Sep. 30, 2014
Segment Reporting Information
Revenues		$ 976.2	[1]	$ 1,130.8		$ 1,972.1	$ 1,606.6	$ 1,082.8		$ 1,148.1		$ 2,455.6	$ 2,004.6	$ 5,685.7		$ 6,691.1	[3]	$ 8,277.3	[3]
Cost of sales														2,437.5		3,736.5	[3]	5,175.7	[3]
Operating income (loss)		(88.6)	[1]	155.7		615.4	305.5	(6.6)		56.1		702.1	83.3	988		834.9	[3]	1,005.6	[3]
Loss from equity investees		(0.1)	[1]	0		0	(0.1)	(0.1)		0		(0.1)	(1)	(0.2)		(1.2)	[3]	(0.1)	[3]
Loss on extinguishments of debt		(11.8)	[1]	(37.1)		0	0	0		0		0	0	(48.9)		0		0
Interest expense														(228.9)		(241.9)	[3]	(237.7)	[3]
Income (loss) before income taxes														710		591.8	[3]	767.8	[3]
Net income (loss) attributable to UGI		(43.8)	[1]	$ 60.7		$ 233.2	$ 114.6	(9.2)		$ 9.6		$ 246.5	$ 34.1	364.7		281	[3]	337.2	[3]
Depreciation and amortization														400.9		374.1	[3]	362.9	[3]
Noncontrolling interests’ net income (loss)														124.1		133	[3]	195.4	[3]
Total assets		10,847.2						10,514.2	[3]					10,847.2		10,514.2	[3]	10,062.6	[3]
Short-term borrowings		291.7						189.9	[3]					291.7		189.9	[3]	210.8	[3]
Capital expenditures														604.6		475.4	[3]	436.4	[3]
Investments in equity investees		25.9						16.2	[3]					25.9		16.2	[3]	0.6	[3]
Goodwill		2,989						2,953.4	[3]					2,989		2,953.4	[3]	2,833.4	[3]
Pretax gains (losses) on unsettled commodity derivative instruments														91.6		(119.1)		(18)
AmeriGas Propane
Segment Reporting Information
Loss on extinguishments of debt														(48.9)		0		0
Interest expense														(164.1)		(162.8)		(165.6)
Income (loss) before income taxes														143.3		264.8		306.4
Depreciation and amortization														190		194.9		197.2
Partnership Adjusted EBITDA														543		619.2		664.8
UGI France | Term Loan
Segment Reporting Information
Pretax loss on early extinguishment of debt																10.3
Eliminations
Segment Reporting Information
Revenues	[4]													(143.9)		(231.4)	[3]	(321.3)	[3]
Cost of sales	[4]													(141.5)		(227.6)	[3]	(317.7)	[3]
Operating income (loss)														0.2		(0.9)	[3]	0.2	[3]
Loss from equity investees														0		0	[3]	0	[3]
Loss on extinguishments of debt														0
Interest expense														0		0	[3]	0	[3]
Income (loss) before income taxes														0.2		(0.9)	[3]	0.2	[3]
Net income (loss) attributable to UGI														0.1		(0.6)	[3]	0	[3]
Depreciation and amortization														(0.2)		0	[3]	0	[3]
Noncontrolling interests’ net income (loss)														0		0	[3]	0	[3]
Total assets		(136.6)						(90.4)	[3]					(136.6)		(90.4)	[3]	(86.5)	[3]
Short-term borrowings		0						0	[3]					0		0	[3]	0	[3]
Capital expenditures														0		0	[3]	0	[3]
Investments in equity investees		0						0	[3]					0		0	[3]	0	[3]
Goodwill		0						0	[3]					0		0	[3]	0	[3]
Operating Segments | AmeriGas Propane
Segment Reporting Information
Revenues														2,311.8		2,885.3	[3]	3,712.9	[3]
Cost of sales														864.8		1,340	[3]	2,107.1	[3]
Operating income (loss)														356.3		427.6	[3]	472	[3]
Loss from equity investees														0		0	[3]	0	[3]
Loss on extinguishments of debt														(48.9)
Interest expense														(164.1)		(162.8)	[3]	(165.6)	[3]
Income (loss) before income taxes														143.3		264.8	[3]	306.4	[3]
Net income (loss) attributable to UGI														43.2		61	[3]	63	[3]
Depreciation and amortization														190		194.9	[3]	197.2	[3]
Noncontrolling interests’ net income (loss)														75.9		167.9	[3]	195.8	[3]
Partnership Adjusted EBITDA	[5]													543		619.2	[3]	664.8	[3]
Total assets		4,071.8						4,128.4	[3]					4,071.8		4,128.4	[3]	4,351.4	[3]
Short-term borrowings		153.2						68.1	[3]					153.2		68.1	[3]	109	[3]
Capital expenditures														101.7		102	[3]	113.9	[3]
Investments in equity investees		0						0	[3]					0		0	[3]	0	[3]
Goodwill		1,978.3						1,956	[3]					1,978.3		1,956	[3]	1,945.1	[3]
Operating Segments | UGI Utilities
Segment Reporting Information
Revenues														768.5		1,041.6	[3]	1,086.9	[3]
Cost of sales														289.8		510.8	[3]	562.9	[3]
Operating income (loss)														200.9		241.7	[3]	246.4	[3]
Loss from equity investees														0		0	[3]	0	[3]
Loss on extinguishments of debt														0
Interest expense														(37.6)		(41.1)	[3]	(38.5)	[3]
Income (loss) before income taxes														163.3		200.6	[3]	207.9	[3]
Net income (loss) attributable to UGI														97.4		121.1	[3]	124.1	[3]
Depreciation and amortization														67.3		63.5	[3]	59.2	[3]
Noncontrolling interests’ net income (loss)														0		0	[3]	0	[3]
Total assets		2,743.1						2,506	[3]					2,743.1		2,506	[3]	2,352.1	[3]
Short-term borrowings		112.5						71.7	[3]					112.5		71.7	[3]	86.3	[3]
Capital expenditures														262.5		197.7	[3]	164.2	[3]
Investments in equity investees		0						0	[3]					0		0	[3]	0	[3]
Goodwill		182.1						182.1	[3]					182.1		182.1	[3]	182.1	[3]
Operating Segments | Energy Services
Segment Reporting Information
Revenues														813.8		1,105.5	[3]	1,388.6	[3]
Cost of sales														583.7		840.2	[3]	1,110.2	[3]
Operating income (loss)														141.8		169.6	[3]	178.7	[3]
Loss from equity investees														0		0	[3]	0	[3]
Loss on extinguishments of debt														0
Interest expense														(2.1)		(2.1)	[3]	(2.9)	[3]
Income (loss) before income taxes														139.7		167.5	[3]	175.8	[3]
Net income (loss) attributable to UGI														83.5		97.9	[3]	104.1	[3]
Depreciation and amortization														17.1		15.5	[3]	13.5	[3]
Noncontrolling interests’ net income (loss)														0		0	[3]	0	[3]
Total assets		765.6						687.6	[3]					765.6		687.6	[3]	601.5	[3]
Short-term borrowings		25.5						49.5	[3]					25.5		49.5	[3]	7.5	[3]
Capital expenditures														136.8		71.3	[3]	69.2	[3]
Investments in equity investees		17.4						6.4	[3]					17.4		6.4	[3]	0	[3]
Goodwill		11.6						11.6	[3]					11.6		11.6	[3]	12.6	[3]
Operating Segments | Electric Generation
Segment Reporting Information
Revenues														62.8		75.9	[3]	85.1	[3]
Cost of sales														28.5		32.2	[3]	39.6	[3]
Operating income (loss)														4.9		13	[3]	18.1	[3]
Loss from equity investees														0		0	[3]	0	[3]
Loss on extinguishments of debt														0
Interest expense														0		0	[3]	0	[3]
Income (loss) before income taxes														4.9		13	[3]	18.1	[3]
Net income (loss) attributable to UGI														3.6		9.6	[3]	12.6	[3]
Depreciation and amortization														13.5		12.5	[3]	10.7	[3]
Noncontrolling interests’ net income (loss)														0		0	[3]	0	[3]
Total assets		272.6						282	[3]					272.6		282	[3]	277.7	[3]
Short-term borrowings		0						0	[3]					0		0	[3]	0	[3]
Capital expenditures														3.6		16.7	[3]	15.6	[3]
Investments in equity investees		0						0	[3]					0		0	[3]	0	[3]
Goodwill		0						0	[3]					0		0	[3]	0	[3]
Operating Segments | UGI France
Segment Reporting Information
Revenues														1,344.7		1,122.2	[3]	1,295.5	[3]
Cost of sales														597.6		628	[3]	848.1	[3]
Operating income (loss)														166.1		75.9	[3]	79.1	[3]
Loss from equity investees														(0.2)		(1.2)	[3]	(0.1)	[3]
Loss on extinguishments of debt														0
Interest expense														(20.8)		(31.6)	[3],[6]	(25.1)	[3]
Income (loss) before income taxes														145.1		43.1	[3]	53.9	[3]
Net income (loss) attributable to UGI														84.2		27.5	[3]	20.6	[3]
Depreciation and amortization														90.5		63.7	[3]	54.5	[3]
Noncontrolling interests’ net income (loss)														(0.1)		0	[3]	(0.4)	[3]
Total assets		2,338.8						2,331.8	[3]					2,338.8		2,331.8	[3]	1,656.8	[3]
Short-term borrowings		0.4						0.1	[3]					0.4		0.1	[3]	0	[3]
Capital expenditures														75.8		65	[3]	50.2	[3]
Investments in equity investees		4.6						6	[3]					4.6		6	[3]	0	[3]
Goodwill		723.2						721.4	[3]					723.2		721.4	[3]	601.2	[3]
Operating Segments | Flaga & Other
Segment Reporting Information
Revenues														524.1		686.3	[3]	1,026.9	[3]
Cost of sales														306.2		492	[3]	809.9	[3]
Operating income (loss)														40.5		36.9	[3]	38.4	[3]
Loss from equity investees														0		0	[3]	0	[3]
Loss on extinguishments of debt														0
Interest expense														(3.6)		(3.6)	[3]	(4.9)	[3]
Income (loss) before income taxes														36.9		33.3	[3]	33.5	[3]
Net income (loss) attributable to UGI														27.4		25.2	[3]	27.7	[3]
Depreciation and amortization														21.9		23.2	[3]	27.1	[3]
Noncontrolling interests’ net income (loss)														0.1		(0.1)	[3]	0	[3]
Total assets		526.3						529.1	[3]					526.3		529.1	[3]	643.6	[3]
Short-term borrowings		0.1						0.5	[3]					0.1		0.5	[3]	8	[3]
Capital expenditures														24.1		22.5	[3]	23	[3]
Investments in equity investees		3.9						3.8	[3]					3.9		3.8	[3]	0.6	[3]
Goodwill		93.8						82.3	[3]					93.8		82.3	[3]	92.4	[3]
Corporate & Other
Segment Reporting Information
Revenues	[7]													3.9		5.7	[3]	2.7	[3]
Cost of sales	[7]													(91.6)		120.9	[3]	15.6	[3]
Operating income (loss)	[7]													77.3		(128.9)	[3]	(27.3)	[3]
Loss from equity investees														0	[7]	0	[3],[7]	0	[3]
Loss on extinguishments of debt														0
Interest expense	[7]													(0.7)		(0.7)	[3]	(0.7)	[3]
Income (loss) before income taxes	[7]													76.6		(129.6)	[3]	(28)	[3]
Net income (loss) attributable to UGI	[7]													25.3		(60.7)	[3]	(14.9)	[3]
Depreciation and amortization	[7]													0.8		0.8	[3]	0.7	[3]
Noncontrolling interests’ net income (loss)	[7]													48.2		(34.8)	[3]	0	[3]
Total assets	[7]	265.6						139.7	[3]					265.6		139.7	[3]	266	[3]
Short-term borrowings	[7]	0						0	[3]					0		0	[3]	0	[3]
Capital expenditures	[7]													0.1		0.2	[3]	0.3	[3]
Investments in equity investees		0	[7]					0	[3],[7]					0	[7]	0	[3],[7]	0	[3]
Goodwill	[7]	$ 0						$ 0	[3]					$ 0		$ 0	[3]	$ 0	[3]
[1]	Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5).
[2]	Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5)
[3]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).
[4]	Represents the elimination of intersegment transactions principally among Midstream & Marketing, UGI Utilities and AmeriGas Propane.
[5]	The following table provides a reconciliation of Partnership Adjusted EBITDA to AmeriGas Propane income before income taxes: 2016 2015 2014Partnership Adjusted EBITDA $543.0 $619.2 $664.8Depreciation and amortization (190.0) (194.9) (197.2)Interest expense (164.1) (162.8) (165.6)Loss on extinguishments of debt (48.9) — —Noncontrolling interests (i) 3.3 3.3 4.4Income before income taxes $143.3 $264.8 $306.4(i)Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.
[6]	UGI France interest expense includes pre-tax costs of $10.3 associated with an extinguishment of debt (see Note 5).
[7]	Corporate & Other results principally comprise (1) revenues and expenses of UGI’s captive general liability insurance company and UGI’s corporate headquarters facility and (2) UGI Corporation’s unallocated corporate and general expenses and interest income. In addition, Corporate & Other results also include the effects of net pre-tax gains and (losses) on commodity derivative instruments not associated with current-period transactions (including such amounts attributable to noncontrolling interests) totaling $91.6, $(119.1) and $(18.0) in Fiscal 2016, Fiscal 2015 and Fiscal 2014, respectively. Corporate & Other assets principally comprise cash and cash equivalents of UGI and its captive insurance company; UGI corporate headquarters’ assets; and our investment in a private equity partnership. Through March 2014, Corporate & Other also had an intercompany loan. The intercompany loan interest is removed in the segment presentation.

Segment Information - Reconcili

Segment Information - Reconciliation of Partnership EBITDA to AmeriGas Propane Operating Income (Details) - USD ($) $ in Millions		3 Months Ended											12 Months Ended
		Sep. 30, 2016	[2]	Jun. 30, 2016	[2]	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	[3]	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
Reconciliation of partnership EBITDA
Depreciation and amortization													$ (400.9)	$ (374.1)	[1]	$ (362.9)	[1]
Interest expense													(228.9)	(241.9)	[1]	(237.7)	[1]
Loss on extinguishments of debt		$ (11.8)		$ (37.1)		$ 0	$ 0	$ 0	$ 0		$ 0	$ 0	(48.9)	0		0
Income before income taxes													$ 710	$ 591.8	[1]	$ 767.8	[1]
General Partner interest in AmeriGas OLP (percentage)													1.01%	1.01%		1.01%
AmeriGas Propane
Reconciliation of partnership EBITDA
Partnership Adjusted EBITDA													$ 543	$ 619.2		$ 664.8
Depreciation and amortization													(190)	(194.9)		(197.2)
Interest expense													(164.1)	(162.8)		(165.6)
Loss on extinguishments of debt													(48.9)	0		0
Noncontrolling interests	[4]												3.3	3.3		4.4
Income before income taxes													$ 143.3	$ 264.8		$ 306.4
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).
[2]	Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5).
[3]	Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5)
[4]	Principally represents the General Partner’s 1.01% interest in AmeriGas OLP.

Condensed Financial Informat116

Condensed Financial Information of Registrant (Parent Company) - Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2013
Current assets
Cash and cash equivalents	$ 502.8	$ 369.7		$ 419.5		$ 389.3
Deferred income taxes	0	7.8
Total current assets	1,423.8	1,459.8
Other assets	217.7	180.4
Total assets	10,847.2	10,514.2	[1]	10,062.6	[1]
Current liabilities
Total current liabilities	1,442	1,678.8
Commitments and contingencies
Common stockholders’ equity:
Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,894,141 and 173,806,991 shares, respectively)	1,201.6	1,214.6
Retained earnings	1,840.9	1,636.9
Accumulated other comprehensive loss	(154.7)	(114.6)
Treasury stock, at cost	(36.9)	(44.9)
Total UGI Corporation stockholders’ equity	2,850.9	2,692
Total liabilities and equity	$ 10,847.2	$ 10,514.2
Condensed Financial Information of Registrant [Abstract]
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	173,894,141	173,806,991
Parent Company
Current assets
Cash and cash equivalents	$ 4.8	$ 1.9		$ 0.8		$ 0.9
Accounts receivable - related parties	9.2	3.3
Deferred income taxes	0	0.4
Prepaid expenses and other current assets	5	4.3
Total current assets	19	9.9
Investments in subsidiaries	2,832.5	2,689.7
Other assets	69.8	58.7
Total assets	2,921.3	2,758.3
Current liabilities
Accounts and notes payable	11.4	10.9
Accrued liabilities	4.4	5
Total current liabilities	15.8	15.9
Noncurrent liabilities	54.6	50.4
Commitments and contingencies
Common stockholders’ equity:
Common Stock, without par value (authorized - 450,000,000 shares; issued - 173,894,141 and 173,806,991 shares, respectively)	1,201.6	1,214.6
Retained earnings	1,840.9	1,636.9
Accumulated other comprehensive loss	(154.7)	(114.6)
Treasury stock, at cost	(36.9)	(44.9)
Total UGI Corporation stockholders’ equity	2,850.9	2,692
Total liabilities and equity	$ 2,921.3	$ 2,758.3
Condensed Financial Information of Registrant [Abstract]
Common stock, shares authorized (in shares)	450,000,000	450,000,000
Common stock, shares issued (in shares)	173,894,141	173,806,991
[1]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).

Condensed Financial Informat117

Condensed Financial Information of Registrant (Parent Company) (Details)	12 Months Ended
	Sep. 30, 2016USD ($)
Parent Company
Guarantee Obligations
Surety bonds indemnified	$ 70,000,000
Maximum amount authorized to guarantee obligations to suppliers and customers	500,000,000
Current carrying value	459,400,000
Flaga
Guarantee Obligations
Amount of floating to fixed rate interest rate swaps at Flaga	$ 1,200,000

Condensed Financial Informat118

Condensed Financial Information of Registrant (Parent Company) - Statements of Income (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		3 Months Ended											12 Months Ended
		Sep. 30, 2016	[1]	Jun. 30, 2016	[1]	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	[2]	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
Condensed Financial Statements, Captions
Revenues		$ 976.2		$ 1,130.8		$ 1,972.1	$ 1,606.6	$ 1,082.8	$ 1,148.1		$ 2,455.6	$ 2,004.6	$ 5,685.7	$ 6,691.1	[3]	$ 8,277.3	[3]
Costs and Expenses
Operating and administrative expenses													1,865.9	1,773.9		1,752.6
Other operating income, net													(22.4)	(44.4)		(36.1)
Total costs and expenses													4,697.7	5,856.2		7,271.7
Operating income		(88.6)		155.7		615.4	305.5	(6.6)	56.1		702.1	83.3	988	834.9	[3]	1,005.6	[3]
Income tax (benefit) expense													221.2	177.8		235.2
Equity in income of unconsolidated subsidiaries		(0.1)		0		0	(0.1)	(0.1)	0		(0.1)	(1)	(0.2)	(1.2)	[3]	(0.1)	[3]
Net income attributable to UGI Corporation		$ (43.8)		$ 60.7		$ 233.2	$ 114.6	$ (9.2)	$ 9.6		$ 246.5	$ 34.1	364.7	281	[3]	337.2	[3]
Comprehensive income attributable to UGI Corporation													$ 324.6	$ 187.6		$ 307.6
Earnings per common share:
Basic (in dollars per share)		$ (0.25)		$ 0.35		$ 1.35	$ 0.66	$ (0.05)	$ 0.06		$ 1.42	$ 0.20	$ 2.11	$ 1.62		$ 1.95
Diluted (in dollars per share)		$ (0.25)		$ 0.34		$ 1.33	$ 0.65	$ (0.05)	$ 0.05		$ 1.40	$ 0.19	$ 2.08	$ 1.60		$ 1.92
Average common shares outstanding (thousands):
Basic (in shares)													173,154	173,115		172,733
Diluted (in shares)													175,572	175,667		175,231
Parent Company
Condensed Financial Statements, Captions
Revenues													$ 0	$ 0		$ 0
Costs and Expenses
Operating and administrative expenses													45.7	48.7		44.5
Other operating income, net	[4]												(45.3)	(48.5)		(44.2)
Total costs and expenses													0.4	0.2		0.3
Operating income													(0.4)	(0.2)		(0.3)
Intercompany interest income													0.1	0.1		0.2
Loss before income taxes													(0.3)	(0.1)		(0.1)
Income tax (benefit) expense													(4)	1.9		2.4
Income (loss) before equity in income of unconsolidated subsidiaries													3.7	(2)		(2.5)
Equity in income of unconsolidated subsidiaries													361	283		339.7
Net income attributable to UGI Corporation													364.7	281		337.2
Other comprehensive (loss) income													(1.1)	0.1		(0.7)
Equity in other comprehensive loss of unconsolidated subsidiaries													(39)	(93.5)		(28.9)
Comprehensive income attributable to UGI Corporation													$ 324.6	$ 187.6		$ 307.6
Earnings per common share:
Basic (in dollars per share)													$ 2.11	$ 1.62		$ 1.95
Diluted (in dollars per share)													$ 2.08	$ 1.60		$ 1.92
Average common shares outstanding (thousands):
Basic (in shares)													173,154	173,115		172,733
Diluted (in shares)													175,572	175,667		175,231
[1]	Includes loss on extinguishments of debt at AmeriGas Partners which decreased net income attributable to UGI Corporation by $6.1 or $0.03 per diluted share for the quarter ended June 30, 2016 and increased net loss attributable to UGI Corporation by $1.8 or $0.01 per diluted share for the quarter ended September 30, 2016 (see Note 5).
[2]	Includes costs associated with an extinguishment of debt at Antargaz which decreased net income attributable to UGI Corporation by $4.6 or $0.03 per diluted share (see Note 5)
[3]	Restated to reflect (1) the current-year changes in the presentation of our UGI Utilities and Energy Services reportable segments and (2) the adoption of new accounting guidance related to debt issuance costs (see Note 2 and Note 3).
[4]	UGI provides certain financial and administrative services to certain of its subsidiaries. UGI bills these subsidiaries monthly for all direct expenses incurred by UGI on behalf of its subsidiaries as well as allocated shares of indirect corporate expense incurred or paid with respect to services provided by UGI. The allocation of indirect UGI corporate expenses to certain of its subsidiaries utilizes a weighted, three-component formula comprising revenues, operating expenses, and net assets employed and considers the relative percentage of such items for each subsidiary to the total of such items for all UGI operating subsidiaries for which general and administrative services are provided. Management believes that this allocation method is reasonable and equitable to its subsidiaries. These billed expenses are classified as “Other operating income, net” in the Statements of Income above.

Condensed Financial Informat119

Condensed Financial Information of Registrant (Parent Company) - Statements of Cash Flows (Details) - USD ($) $ in Millions		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2014
Condensed Financial Statements, Captions
NET CASH PROVIDED BY OPERATING ACTIVITIES		$ 969.7	$ 1,163.8	$ 1,005.4
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used by investing activities		(558.6)	(976.3)	(487.6)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends on Common Stock		(160.7)	(153.5)	(136.1)
Purchases of UGI Common Stock		(47.6)	(34.1)	(39.8)
Issuances of Common Stock		13.7	11.9	10.9
Other		15.5	(3.5)	11.8
Net cash used by financing activities		(275.1)	(217.1)	(475.7)
Cash and cash equivalents increase (decrease)		133.1	(49.8)	30.2
CASH AND CASH EQUIVALENTS
End of year		502.8	369.7	419.5
Beginning of year		369.7	419.5	389.3
Increase (decrease)		133.1	(49.8)	30.2
Dividends from unconsolidated subsidiaries		193.1	271.6	186.4
Parent Company
Condensed Financial Statements, Captions
NET CASH PROVIDED BY OPERATING ACTIVITIES	[1]	195.6	277.2	199.7
CASH FLOWS FROM INVESTING ACTIVITIES
Net investments in unconsolidated subsidiaries		(8.9)	(104.8)	(47.3)
Net cash used by investing activities		(8.9)	(104.8)	(47.3)
CASH FLOWS FROM FINANCING ACTIVITIES
Payment of dividends on Common Stock		(160.7)	(153.5)	(136.1)
Purchases of UGI Common Stock		(47.6)	(34.1)	(39.8)
Issuances of Common Stock		24.5	16.8	23.4
Other		0	(0.5)	0
Net cash used by financing activities		(183.8)	(171.3)	(152.5)
Cash and cash equivalents increase (decrease)		2.9	1.1	(0.1)
CASH AND CASH EQUIVALENTS
End of year		4.8	1.9	0.8
Beginning of year		1.9	0.8	0.9
Increase (decrease)		$ 2.9	$ 1.1	$ (0.1)
[1]	Includes dividends received from unconsolidated subsidiaries of $193.1, $271.6 and $186.4 for the years ended September 30, 2016, 2015 and 2014, respectively.

Valuation and Qualifying Acc120

Valuation and Qualifying Accounts (Details) - USD ($) $ in Millions		12 Months Ended
		Sep. 30, 2016	Sep. 30, 2015		Sep. 30, 2014
Reserves Deducted From Assets in the Consolidated Balance Sheet
Valuation and Qualifying Account
Balance at beginning of year		$ 29.7	$ 39.1		$ 39.5
Charged (credited) to costs and expenses		21.7	31.6		43.5
Balance at end of year		27.3	29.7		39.1
Reserves Deducted From Assets in the Consolidated Balance Sheet | Allowance for Doubtful Accounts
Valuation and Qualifying Account
Other	[1]	(24.1)	(39.6)		(43)
Reserves Deducted From Assets in the Consolidated Balance Sheet | Allowance for Foreign Currency Exchange Effects
Valuation and Qualifying Account
Other	[2]		(1.4)		(0.9)
Other Reserves
Valuation and Qualifying Account
Balance at beginning of year		131.3	59.2		97.6
Charged (credited) to costs and expenses		(5.8)	5.1		0.4
Balance at end of year		114.3	131.3		59.2
Other Reserves | Deferred Tax Assets Valuation Allowance
Valuation and Qualifying Account
Other	[3]	(8.8)	66.1		(34)
Other Reserves | Decrease in Unusable Foreign Operating Loss Carryforwards
Valuation and Qualifying Account
Other	[4]	$ (2.4)	(2.6)
Other Reserves | Acquisitions
Valuation and Qualifying Account
Other			$ 3.5	[5]	$ (4.8)	[4]
[1]	Uncollectible accounts written off, net of recoveries.
[2]	Effects of currency exchange.
[3]	Foreign tax credit valuation allowance adjustment.
[4]	Decrease in unusable foreign operating loss carryforwards.
[5]	Acquisitions